Indicate
by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file
such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants knowledge, in
definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨

At March 15, 2003, there were
18,039,482 shares of Goodrich Petroleum Corporation common stock outstanding. The aggregate market value of shares of common stock held by non-affiliates of the registrant as of March 15, 2003, was approximately $21,235,000 based on a closing price
of $3.66 per share on the New York Stock Exchange on such date.

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes ¨ No x

At June 28, 2002, the aggregate market value of Goodrich Petroleum Corporation common stock held by non-affiliates was $21,059,000.

PART I

Items 1 and 2. Business and Properties.

General

Goodrich Petroleum Corporation and subsidiaries
(Goodrich or the Company) is an independent oil and gas company engaged in the exploration, exploitation, development and production of oil and natural gas properties primarily in the transition zone of south Louisiana and in
north Louisiana, the Gulf Coast of Texas and East Texas. The Company owns working interests in 99 active oil and gas wells located in 20 fields in four states. The Company also owns overriding royalty interest in five oil and gas wells. At December
31, 2002, Goodrich had estimated proved reserves of approximately 7.4 million barrels of oil and condensate and 29.1 billion cubic feet (Bcf) of natural gas, or an aggregate of 73.7 Bcf equivalent (Bcfe) with a pre-tax
present value of future net revenues, discounted at 10%, of $151.4 million and an after-tax Standardized Measure value of $124.3 million.

The Companys principal executive offices are located at 808 Travis Street, Suite 1320, Houston, Texas 77002. The Company also has
offices in Shreveport, Louisiana. At March 15, 2003, the Company had 37 employees.

Company Background

Goodrich resulted from a business combination on August 15, 1995 between La/Cal Energy Partners (La/Cal) and Patrick Petroleum Company and subsidiaries (Patrick). La/Cal was a
privately held independent oil and gas partnership formed in July 1993 engaged in the development, production and acquisition of oil and natural gas properties, primarily in southern Louisiana. Patrick was a NYSE listed independent oil and gas
company engaged in the exploration, production, development and acquisition of oil and natural gas properties in the continental United States. Patricks oil and gas operations and properties were primarily located in West Texas and Michigan at
the time of the combination, with additional operations and properties in certain western states.

Oil and Gas Operations and Properties

The following is a summary description of the Companys oil and gas properties.

Louisiana

The majority of the Companys proved oil and natural gas reserves are in the transition zone of the south Louisiana producing region.
This region refers to the geographic area that covers the onshore and in-land waters of south Louisiana lying in the southern half of Louisiana, which is one of the most prolific oil and natural gas producing sedimentary basins. The region generally
contains sedimentary sandstones, which are of high qualities of porosity and permeabilities. There is a myriad of types of reservoir traps found in the region. These traps are generally formed by faulting, folding and subsurface salt movement, or a
combination of one or more of these.

The
formations found in the southern Louisiana producing region range in depth from 1,000 feet to 20,000 feet below the surface. These formations range from the Sparta and Frio formations in the northern part of the region to Miocene and Pleistocene in
the southern part of the region. The Companys production comes predominately from Miocene and Frio age formations.

Burrwood and West Delta Fields. The Burrwood and West Delta fields, located in Plaquemines Parish,
Louisiana, were discovered in 1955 by Chevron. The fields lie upthrown to a large down-to-the southeast growth fault system with the structure striking northeast-southwest and dipping northwestward in a counter-regional direction. The fields have
collectively produced over 49 million barrels of oil and 144 Bcf of natural gas. The

2

productive sands are Miocene and Pliocene age sands ranging in depth from 6,300 feet to approximately 11,700 feet. There are currently 19
active producing wells in the fields.

Goodrich
acquired a 95% working interest in approximately 8,600 acres of the Burrwood and West Delta fields through an acquisition that closed on March 2, 2000 with an effective date of January 1, 2000. On March 12, 2002, the Company, in an effort to
monetize a portion of the value created in the two fields and enhance its liquidity position, completed the sale of a thirty percent (30%) working interest in the existing production and shallow rights, and a fifteen percent (15%) working interest
in the deep rights below 10,600 feet, in the fields for $12 million to Malloy Energy Company, LLC led by Patrick E. Malloy, III and participated in by Sheldon Appel, both members of the Companys Board of Directors (Mr. Malloy is now Chairman
of the Companys Board of Directors), as well as Josiah Austin, who subsequently became a member of the Companys Board of Directors. The sale price was determined by discounting the present value of the acquired interest in the
fields proved, probable and possible reserves using prevailing oil and gas prices. The Company retains an approximate sixty-five percent (65%) working interest in the existing production and shallow rights, and a thirty-two and one-half
percent (32.5%) working interest in the deep rights after the close of the transaction. In conjunction with the sale, the investor group provided a $7.7 million line of credit. The $7.7 million line of credit, which reduced to $5.0 million on
January 1, 2003, is subordinate to the Companys senior credit facility. The line of credit can be used for acquisitions, drilling, development and general corporate purposes until December 31, 2004. The investor group retains the option,
through December 31, 2004, to convert the amount outstanding under the credit line, and/or provide cash on any unused credit to a maximum of $7.7 million in the first year, reduced to $5.0 million after December 31, 2002, into working interests in
any acquisition(s) the Company may make in Louisiana prior to January 1, 2005. The conversion of the credit facility will be on a pro-rata basis with the Company and may not exceed a maximum of $7.7 million, reduced to $5.0 million after December
31, 2002, or thirty percent (30%) of any potential acquisition(s). To date, no borrowings have been made under the credit facility.

The Company recorded a non-recurring gain of approximately $2.4 million in the first quarter of 2002 as a result of the sale. The proceeds
were used to reduce outstanding debt under its senior credit facility.

Lafitte Field. The Lafitte field is located in Jefferson Parish, Louisiana and was discovered in 1935 by Texaco. The Lafitte field is a large, north-south elongated salt dome anticline feature.
There are currently more than thirty (30) defined productive sands, which have collectively produced in excess of 264 million barrels of oil and 319 Bcf of natural gas. The productive sands are Miocene and Pliocene age sands ranging in depth from
3,000 feet to approximately 12,000 feet. There are currently 24 active producing wells in the field. In September 1999, the Company acquired a non-operated working interest of approximately 49% in the Lafitte field with respect to the fields
leases, surface facilities and equipment and a non-operated working interest of approximately 45% in the active producing wells. In November 1999, the Company acquired additional interests, resulting in a field-wide non-operated working interest of
approximately 49%.

Second Bayou
Field. The Second Bayou field is located in Cameron Parish, Louisiana and was discovered in 1955 by the Sun Texas Company. Goodrich is the operator of eight producing wells, four of which are dually completed, and has an
average working interest of approximately 29% in 1,395 gross acres. To date, the field has produced over 425 Bcf of natural gas and 3.6 million barrels of oil from multiple Miocene aged sands ranging from 4,000 to 15,200 feet.

Pecan Lake Field. The Pecan Lake
field was discovered in 1944 by the Superior Oil Company. Geologically, the field is comprised of a relatively low relief, four-way closure and multiple stacked pay sands. The Pecan Lake field comprises approximately 870 gross leased acres in
Cameron Parish, Louisiana, approximately 42 miles southeast of Lake Charles, Louisiana. The field has produced from over 15 Miocene sands ranging in depths from 7,500 to 11,800 feet, which have been predominately gas and gas condensate reservoirs.
These sand reservoirs are characterized by generally widespread development and strong waterdrive production mechanisms. The field has produced in excess of 354 Bcf of gas and 798,000 barrels of condensate. All of the field production to date has
come from normal pressured reservoirs. The Company is the operator of four producing wells with working interests ranging from approximately 43% to 47%.

3

Isle St.
Jean Charles Field. Isle St. Jean Charles field is located in Terrebonne Parish, Louisiana. The field is a northwest extension of the Bayou Jean LaCroix field located in the southeastern area of the Parish. These fields
are trapped on a four-way closure, downthrown on a major east-west trending down to the south fault.

Production is from multiple Miocene-aged sands, which are normally pressured and range in depth from 9,000 feet to 13,000 feet. The field
was developed primarily in the 1950s by Exxon and reservoirs have exhibited both depletion and water drive mechanisms. To date, this field has produced in excess of 57 Bcf of gas and 6.61 million barrels of oil and condensate.

Goodrich acquired its approximate 34% working interest in its
leasehold of approximately 425 acres through both acreage acquisitions and a farmout. The Company operates the one dually-completed well in the field.

Lake Raccourci Field. The Lake Raccourci field located in Terrebonne Parish, Louisiana was discovered by a
predecessor to Exxon in 1949, with the field extended to the south by a predecessor to Amoco in 1958. Geologically, the field is a large four-way dipping closure, which is cross-cut by numerous northeast-southwest striking down to the south faults.
The field has produced from a minimum of 18 different Miocene age sandstones, ranging in depth from 9,000 to 16,500 feet. These normally and abnormally pressured reservoirs exhibit depletion, water and combination drive mechanisms, and have produced
in excess of 834 billion cubic feet of gas and 20 million barrels of oil and condensate.

Goodrich acquired its average 27% working interest in the field through a farmout from a predecessor to Apache in July 1996 and a separate farmout from Exxon. In December 2001, the Company purchased
Exxons interest in one of the wells in the field. The Company controls approximately 1,079 acres in the field, which currently has seven producing wells.

Other. The Company maintains ownership interests in acreage and wells in several additional fields in
Louisiana, including the (i) Opelousas field, located in St. Landry Parish, (ii) Sibley field, located in Webster Parish, (iii) City of Lake Charles field, located in Calcasieu Parish, (iv) South Drew field, located in Ouachita Parish, (v) Mosquito
Bay field, located in Terrebonne Parish, (vi) Kings Ridge field, located in Lafourche Parish, and (vii) Ada field, located in Bienville Parish

Texas

Goodrich explores and has production in the western, eastern and southern regions of Texas.

Sean Andrew Field. The Sean
Andrew field in Dawson County, Texas was discovered by the Company in 1994 utilizing the Companys 375 square mile 3-D seismic database in West Texas. The Company is the operator of two wells in the field and holds an approximate 37.5% working
interest.

Marholl
Field. The Marholl field is a Siluro-Devonian (Fussellman) field in Dawson County, Texas, discovered in 1995 through the use of 3-D seismic. The Company operates two wells in the field with an approximate 23% working
interest.

Mary Blevins
Field. The Mary Blevins field is located in Smith County, Texas. It was a new discovery that is fault separated from Hitts Lake field, which was discovered in 1953 by Sun Oil. Currently there are four producing wells in
the field in which Goodrich serves as operator, having an approximate 48% working interest in 782 gross acres. To date, Hitts Lake has produced over 14 million barrels of oil and Mary Blevins has produced over 551,000 barrels of oil from the Paluxy,
which occurs at a depth of approximately 7,300 feet.

Other. The Company maintains ownership interests in acreage and wells in several additional fields in Texas including the (i) Ackerly field, located in Dawson and Howard Counties, (ii) Lamesa Farms
field, located in Dawson County, (iii) Midway field, located in San Patricio County, and (iv) Mott Slough field, located in Wharton County.

4

Australia

Goodrich has interests in two offshore exploration permits in
the Carnarvon Basin of Western Australia.

The
Carnarvon Basin is two-thirds the size of the Gulf of Mexico and has produced in excess of 4.3 TCF and 550 million barrels of oil from less than 1,000 wells. The Carnarvon Basin retains significant exploration potential. Additional strengths of the
basin include large inexpensive acreage blocks, vast available geological and geophysical data sets, existing and expanding petroleum infrastructure and increasing domestic demands for natural gas.

EP-395. Goodrich Petroleum has a
6.9% non-operated working interest in an approximate 240 square kilometer Exploration Permit. Since 1995 the partners have reprocessed the original 2-D seismic data sets, shot an approximate 38 square km 3-D seismic survey, and shot an approximate
additional 93 km of high quality 2-D seismic.

EP-397. This Permit covers 160 square kilometers in which the Company has a 33% non-operated working interest. The 130 km of available seismic has been reprocessed and interpreted with several prospect
leads. The Company is scheduled to participate in a well on EP-397, its Banjo Prospect, during the first half of 2003. The Company has already paid its estimated share of the dry hole costs in escrow for the well in the amount of approximately
$650,000.

Oil and Natural Gas Reserves

The following tables set forth summary information with
respect to the Companys proved reserves as of December 31, 2002 and 2001, as estimated by the Company by compiling reserve information, substantially all of which was prepared by the engineering firm of Coutret and Associates, Inc.

Net Reserves

Pre-Tax Present

Value of Future

Net Revenues

(in millions)

After-Tax

Standardized Measure of Discounted Future

Net Revenues

(in millions)

Category

Oil (Bbls)

Gas (Mcf)

Bcfe(1)

December 31, 2002

Proved Developed

2,556,670

15,203,255

30.5

$

68.06

Proved Undeveloped

4,884,670

13,866,295

43.2

83.30

Total Proved

7,441,340

29,069,550

73.7

$

151.36

$

124.3

December 31, 2001

Proved Developed

3,399,610

16,692,390

37.1

$

42.39

Proved Undeveloped

5,350,810

17,263,860

49.4

36.50

Total Proved

8,750,420

33,956,250

86.5

$

78.89

$

73.12

(1)

Estimated by the Company using a conversion ratio of 1.0 Bbl/6.0 Mcf.

Reserve engineering is a subjective process of estimating underground accumulations of crude oil, condensate
and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The quantities of oil and natural gas
that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and natural gas sales prices may all differ from those assumed in these estimates. Therefore, the pre-tax Present
Value of Future Net Revenues amounts shown above should not be construed as the current market value of the estimated oil and natural gas reserves attributable to the Companys properties.

5

In accordance
with the guidelines of the Securities and Exchange Commission (SEC), the engineers estimates of future net revenues from the Companys properties and the pre-tax Present Value of Future Net Revenues thereof are made using oil and natural
gas sales prices in effect as of the dates of such estimates and are held constant throughout the life of the properties, except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price
escalations. The prices as of December 31, 2002, and 2001 used in such estimates averaged $4.35 and $2.51 per Mcf, respectively, of natural gas and $28.80 and $17.91 per Bbl, respectively, of crude oil/condensate.

Productive Wells

The following table sets forth the number of active well
bores in which the Company maintains ownership interests as of December 31, 2002:

Oil

Gas

Net

Gross(1)

Net(2)

Gross(1)

Net(2)

Gross(1)

Net(2)

Louisiana

46.00

23.39

30.00

12.43

76.00

35.82

Michigan





5.00

0.05

5.00

0.05

New Mexico





1.00

0.03

1.00

0.03

Texas

14.00

7.01

3.00

0.20

17.00

7.21

Total Productive Wells

60.00

30.40

39.00

12.71

99.00

43.11

(1)

Does not include royalty or overriding royalty interests.

(2)

Net working interest.

Productive wells consist of producing wells and wells capable of production, including gas wells awaiting pipeline connections. A gross
well is a well in which the Company maintains an ownership interest, while a net well is deemed to exist when the sum of the fractional working interests owned by the Company equals one. Wells that are completed in more than one producing horizon
are counted as one well. Of the gross wells reported above, seven had multiple completions.

Acreage

The following table summarizes the Companys gross and net developed and undeveloped natural gas and oil acreage under lease as of December 31, 2002. Acreage in which the Companys interest is limited to a royalty or
overriding royalty interest is excluded from the table.

Gross

Net

Developed acreage

Louisiana

11,569

6,662

Michigan

1,920

19

Texas

1,181

440

New Mexico

640

19

Undeveloped acreage

Offshore Australia

98,841

17,306

Louisiana

7,331

3,633

Texas

499

263

Total

121,981

28,342

Undeveloped acreage is considered to be those lease acres on which wells have not been drilled or completed to the extent that would permit the production of commercial quantities of natural gas or oil, regardless of whether or not
such acreage contains proved reserves. As is customary in the oil and gas industry,

6

the Company can retain its interest in undeveloped acreage by drilling activity that establishes commercial production sufficient to maintain
the leases or by payment of delay rentals during the remaining primary term of such a lease. The natural gas and oil leases in which the Company has an interest are for varying primary terms; however, most of the Companys developed lease
acreage is beyond the primary term and is held so long as natural gas or oil is produced.

Operator Activities

Goodrich Petroleum operates a majority in value of the Companys producing properties, and will generally seek to become the operator of record on properties it drills or acquires in the future.

Drilling Activities

The following table sets forth the drilling activities of the
Company for the last three years. (As denoted in the following table, Gross wells refers to wells in which a working interest is owned, while a net well is deemed to exist when the sum of fractional ownership working
interests in gross wells equals one.)

Year Ended December 31,

2002

2001

2000

Gross

Net

Gross

Net

Gross

Net

Development Wells:

Productive





4.00

3.39

3.00

1.77

Non-Productive









1.00

49

Total





4.00

3.39

4.00

2.26

Exploratory Wells:

Productive

2.00

1.13

1.00

17

2.00

93

Non-Productive





2.00

1.40

2.00

1.00

Total

2.00

1.13

3.00

1.57

4.00

1.93

Total Wells:

Productive

2.00

1.13

5.00

3.56

5.00

2.70

Non-Productive





2.00

1.40

3.00

1.49

Total

2.00

1.13

7.00

4.96

8.00

4.19

7

Net Production, Unit Prices
and Costs

The following table presents
certain information with respect to oil, gas and condensate production attributable to the Companys interests in all of its fields, the revenue derived from the sale of such production, average sales prices received and average production
costs during each of the years in the three-year period ended December 31, 2002.

2002

2001

2000

Net Production:

Natural gas (Mcf)

2,477,790

3,823,227

3,394,921

Oil (barrels)

451,564

581,680

571,766

Natural gas equivalents (Mcfe) (1)

5,187,174

7,313,307

6,825,517

Average Net Daily Production:

Natural gas (Mcf)

6,788

10,475

9,301

Oil (Bbls)

1,237

1,594

1,566

Natural gas equivalents (Mcfe) (1)

14,211

20,039

18,697

Average Sales Price Per Unit (2):

Natural gas (per Mcf)

$

3.08

3.97

3.95

Oil (per Bbl)

$

25.09

24.67

25.55

Other Data:

Lease operating expense (per Mcfe) (3)

$

1.50

0.90

0.69

Production taxes (per Mcfe).

$

0.32

0.26

0.32

DD & A (per Mcfe)

$

1.05

0.94

0.87

Exploration (per Mcfe)

$

0.22

0.57

0.41

(1)

Estimated by the Company using a conversion ratio of 1.0 Bbl/6.0 Mcf.

(2)

See Results of Operations under Item 7 for discussion of the effects of hedging on results.

(3)

See Results of Operations under Item 7 for discussion of increase in lease operating expense in 2002.

The Companys acquisition strategy calls for the
acquisition of mature oil and gas fields with declining production profiles, established production histories and multiple productive sands that have been overlooked and/or starved of capital. Acquisitions of this type generally require significant
lease operation, exploration and capital expenditure cash outlays during initial years of ownership. The Companys Lafitte, Burrwood and West Delta fields acquisitions in late 1999 and early 2000, were strategic acquisitions that fit the
aforementioned profile, and account for the increased unit costs noted above in the periods presented above.

Oil and Gas Marketing and Major Customers

Marketing. Goodrichs natural gas production is sold under spot or market-sensitive contracts to
various gas purchasers on short-term contracts. Goodrichs natural gas condensate is sold under short-term rollover agreements based on current market prices. The Companys crude oil production is marketed to several purchasers based on
short-term contracts.

Customers. Due to the nature of the industry, the Company sells its oil and natural gas production to a limited number of purchasers and, accordingly, amounts receivable from such purchasers could be
significant. Revenues from these sources as a percent of total revenues for the periods presented were as follows:

Year Ended

December 31,

2002

2001

2000

Reliant Energy

45

%

56

%

48

%

Conoco, Inc

17

%





Shell Trading

17

%





Genesis Crude Oil, L.P.

5

%

22

%

27

%

Gulfmark Energy, Inc.





10

%

8

Effective
January 1, 2003, the Company contracted with Louis Dreyfus Corporation as its major gas purchaser in lieu of Reliant Energy.

Competition

The oil and gas industry is highly competitive. Major and independent oil and gas companies, drilling and production acquisition programs
and individual producers and operators are active bidders for desirable oil and gas properties, as well as the equipment and labor required to operate those properties. Many competitors have financial resources substantially greater than those of
the Company, and staffs and facilities substantially larger than those of the Company. The availability of a ready market for the oil and gas production of the Company will depend in part on the cost and availability of alternative fuels, the level
of consumer demand, the extent of domestic production of oil and gas, the extent of importation of foreign oil and gas, the cost of and proximity to pipelines and other transportation facilities, regulations by state and federal authorities and the
cost of complying with applicable environmental regulations.

Regulations

The
availability of a ready market for any natural gas and oil production depends upon numerous factors beyond the Companys control. These factors include regulation of natural gas and oil production, federal and state regulations governing
environmental quality and pollution control, state limits on allowable rates of production by a well or proration unit, the amount of natural gas and oil available for sale, the availability of adequate pipeline and other transportation and
processing facilities and the marketing of competitive fuels. For example, a productive natural gas well may be shut-in because of an oversupply of natural gas or the lack of an available natural gas pipeline in the areas in which the
Company may conduct operations. State and federal regulations generally are intended to prevent waste of natural gas and oil, protect rights to produce natural gas and oil between owners in a common reservoir, control the amount of natural gas and
oil produced by assigning allowable rates of production and control contamination of the environment. Pipelines are subject to the jurisdiction of various federal, state and local agencies as well.

Environmental Regulation

Various federal, state and local laws and regulations
covering the discharge of materials into the environment, or otherwise relating to the protection of the environment, may affect the Companys operations and costs as a result of their effect on oil and gas development, exploration and
production operations. It is not anticipated that the Company will be required in the near future to expend amounts that are material in relation to its total capital expenditures program by reason of environmental laws and regulations but, inasmuch
as such laws and regulations are frequently changed by both federal and state agencies, the Company is unable to predict the ultimate cost of continued compliance. Additionally, see existing EPA matters discussed in Item 3Legal Proceedings.

State statutes and regulations require permits
for drilling operations, drilling bonds and reports concerning operations. In addition, there are state statutes, rules and regulations governing conservation matters, including the unitization or pooling of oil and gas properties, establishment of
maximum rates of production from oil and gas wells and the spacing, plugging and abandonment of such wells. Such statutes and regulations may limit the rate at which oil and gas could otherwise be produced from the Companys properties and may
restrict the number of wells that may be drilled on a particular lease or in a particular field.

Risk Factors

The Companys Success is Dependent on Oil and Gas Prices. Goodrichs success will depend on the market prices of oil and gas. These market prices tend to fluctuate significantly in
response to factors beyond the

9

Companys control. The prices the Company receives for its crude oil production are based on global market conditions. The continued
threat of war in the Middle East, the continuing economic crisis in Venezuela (a major oil exporter), and actions of OPEC and its maintenance of production constraints, as well as other economic, political, and environmental factors will continue to
affect world supply. Natural gas prices fluctuate significantly in response to numerous factors including the U.S. economic environment, North American weather patterns, other factors affecting demand such as substitute fuels, the impact of drilling
levels on crude oil and natural gas supply, and the environmental and access issues that limit future drilling activities for the industry.

The year 2002 began with lower commodity prices as a result of the global economic downturn and decreases in demand. During 2002, crude
oil prices increased due to a combination of factors including fears of war in Iraq (and the resulting impact on the Middle East), Venezuelan strikes that reduced oil exports, and continued OPEC production discipline. Natural gas prices also
increased throughout 2002 as U.S. productive capacity declined and as demand increased in the fourth quarter due, in part, to belownormal temperatures. Commodity prices ended the year at their highest levels and have remained strong in 2003.
The Company expects that commodity prices will continue to fluctuate significantly in the future.

Changes in commodity prices significantly affect the Companys capital resources, liquidity and expected operating results. Price
changes directly affect revenues and can indirectly impact expected production by changing the amount of funds available to reinvest in exploration and development activities. Reductions in oil and gas prices not only reduce revenues and profits,
but could also reduce the quantities of reserves that are commercially recoverable. Significant declines in prices could result in noncash charges to earnings due to impairment. The Company uses derivative financial instruments to hedge its
exposure to price risk from changing commodity prices and the Company has hedged a substantial portion of its anticipated production for 2003.

The Companys Operations Require Significant Capital Expenditures. Goodrich must make a substantial
amount of capital expenditures for the acquisition, exploration and development of oil and gas reserves. Historically, the Company has paid for these expenditures with cash from operating activities, proceeds from debt and equity financings and
asset sales. Goodrichs revenues or cash flows could be reduced because of lower oil and gas prices or for other reasons. If Goodrichs revenues or cash flows decrease, the Company may not have the funds available to replace reserves or to
maintain production at current levels. If this occurs, the Companys production will decline over time. Other sources of financing may not be available if Goodrichs cash flows from operations are not sufficient to fund its capital
expenditure requirements. Where Goodrich is not the majority owner or operator of an oil and gas property, such as the Lafitte field, it may have no control over the timing or amount of capital expenditures associated with the particular property.
If Goodrich cannot fund its capital expenditures, its interests in some properties may be reduced or forfeited.

The Companys Oil and Gas Reserve Information Is Estimated. The proved oil and gas reserve information
included in this document represents estimates. These estimates are based on reports prepared by consulting reserve engineers and were calculated using oil and gas prices as of December 31, 2002. These prices could change. Petroleum engineering is a
subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. Estimates of economically recoverable oil and gas reserves and of future net cash flows necessarily depend upon a number of
variable factors and assumptions, including:



historical production from the area compared with production from other similar producing areas;

Because all
reserve estimates are to some degree subjective, each of the following items may differ materially from those assumed in estimating reserves:



the quantities of oil and gas that are ultimately recovered;



the production and operating costs incurred;



the amount and timing of future development expenditures; and



future oil and gas sales prices.

Furthermore, different reserve engineers may make different estimates of reserves and cash flows based on the same available data.
Goodrichs actual production, revenues and expenditures with respect to reserves will likely be different from estimates and the differences may be material. The discounted future net cash flows included in this document should not be
considered as the current market value of the estimated oil and gas reserves attributable to Goodrichs properties. As required by the SEC, the estimated discounted future net cash flows from proved reserves are generally based on prices and
costs as of the date of the estimate, while actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by factors such as:



the amount and timing of actual production;



supply and demand for oil and gas;



increases or decreases in consumption; and



changes in governmental regulations or taxation.

In addition, the 10% discount factor, which is required by the SEC to be used to calculate discounted future net cash flows for reporting
purposes, is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the Company or the oil and gas industry in general.

Oil and Gas Operations Are Subject to Various Economic
Risks. The oil and gas operations of Goodrich are subject to the economic risks typically associated with exploration, development and production activities, including the necessity of significant expenditures to locate
and acquire properties and to drill exploratory wells. In conducting exploration and development activities, the presence of unanticipated pressure or irregularities in formations, miscalculations or accidents may cause Goodrichs exploration,
development and production activities to be unsuccessful. This could result in a total loss of Goodrichs investment in a particular property. If exploration efforts are unsuccessful in establishing proved reserves and exploration activities
cease, the amounts accumulated as unproved costs would be charged against earnings as impairments. In addition, the cost and timing of drilling, completing and operating wells is often uncertain.

Drilling Oil and Gas Wells Could Involve Blowouts,
Environmental Hazards and Other Risks. The nature of the oil and gas business involves certain operating hazards such as well blowouts, cratering, explosions, uncontrollable flows of oil, gas or well fluids, fires,
formations with abnormal pressures, pollution, releases of toxic gas and other environmental hazards and risks. Any of these operating hazards could result in substantial losses to Goodrich. As a result, substantial liabilities to third parties or
governmental entities may be incurred. The payment of these amounts could reduce or eliminate the funds available for exploration, development or acquisitions. These reductions in funds could result in a loss of Goodrichs properties.
Additionally, some of Goodrichs oil and gas operations are located in areas that are subject to weather disturbances such as hurricanes. Some of these disturbances can be severe enough to cause substantial damage to facilities and possibly
interrupt production. In accordance with customary industry practices, Goodrich maintains insurance against some, but not all, of such risks and losses. The occurrence of an event that is not fully covered by insurance could have a material adverse
effect on the financial position and results of operations of Goodrich.

11

Competition
Within the Oil and Gas Industry is Intense. The exploration and production business is highly competitive. Many of Goodrichs competitors have substantially larger financial resources, staffs and facilities than
Goodrich. These competitors include other independent oil and gas producers, as well as major oil companies.

Government Agencies Can Increase Costs and Can Terminate or Suspend Operations. Goodrichs business is
subject to foreign, federal, state and local laws and regulations relating to the exploration for, and the development, production and transportation of, oil and gas, as well as environmental and safety matters. Many of these laws and regulations
have become stricter in recent years. These laws and regulations often impose greater liability on a larger number of potentially responsible parties. Under some circumstances, the State of Louisiana may require the operations of Goodrich on state
leases to be suspended or terminated. These circumstances include Goodrichs failure to pay royalties, Goodrichs failure to comply with safety and environmental regulations. This could have a material adverse effect on Goodrichs
financial condition and operations.

Item
3. Legal Proceedings.

The U.S. Environmental Protection Agency (EPA) has identified the Company as a potentially responsible party (PRP) for the cost of clean-up of hazardous substances at an oil field waste
disposal site in Vermilion Parish, Louisiana. The Company estimates that the remaining cost of long-term clean-up of the site will be approximately $3.5 million, with the Companys percentage of responsibility estimated to be approximately
3.05%. As of December 31, 2002, the Company had paid $321,000 in costs related to this matter and accrued $122,500 for the remaining liability. These costs have not been discounted to their present value. The EPA and the PRPs will continue to
evaluate the site and revise estimates for the long-term clean-up of the site. There can be no assurance that the cost of clean-up and the Companys percentage responsibility will not be higher than currently estimated. In addition, under the
federal environmental laws, the liability costs for the clean-up of the site is joint and several among all PRPs. Therefore, the ultimate cost of the clean-up to the Company could be significantly higher than the amount presently estimated or
accrued for this liability.

On February 8, 2000,
the Company commenced a suit against the operator and joint owner of the Lafitte field, alleging certain items of misconduct and violations of the agreements associated primarily with the joint acquisition of and unfettered access to a license to
3-D seismic data over the field. The operator has counter-claimed against Goodrich on the grounds that Goodrich was obligated to post a bond to secure the plugging and abandonment obligations in the field. On November 1, 2002 the 125th Judicial District Court of Harris County, Texas, ruled in favor of the Company stating (1) The Sale and Assignment between the
Company and the operator assigned the same rights to the 3-D seismic data that the operator had pursuant to the operators data use license agreement from Texaco Exploration and Production, Inc. (TEPI); and (2) Also pursuant to the
terms of the Sale and Assignment, Goodrich is required to post 49% of the bond liability to TEPI at such time that TEPI requests it. The Court has not determined whether TEPI has already issued the request that would require the Company to post 49%
of the bond liability to TEPI. However, in a statement to the Court, TEPI stated that whatever may be the obligation between the operator and Goodrich regarding the requirement, if any, for Goodrich to post a bond in favor of the operator covering
Goodrichs P&A obligations, TEPI does not claim that it is entitled to any bond unless and until the operators total shareholder value (as defined in the Purchase and Sale Agreement between the operator and TEPI) falls below $80
million. The damages portion of the suit is ongoing and it is too early to predict a likely outcome, however, this action is not expected to have a significantly adverse impact on the operations or financial position of the Company.

The Company is party to additional lawsuits arising in the
normal course of business. The Company intends to defend these actions vigorously and believes, based on currently available information, that adverse results or judgments from such actions, if any, will not be material to its financial position or
results of operations.

The Companys common stock is traded on the New York Stock Exchange under the symbol GDP.

At March 15, 2003 the number of holders of record of the Companys common stock without determination of the number of individual
participants in security position was 1,648 with 18,039,482 shares outstanding. High and low sales prices for the Companys common stock for each quarter during the calendar years 2002 and 2001 are as follows:

2002

2001

Quarter Ended

High

Low

High

Low

March 31

$

4.63

3.65

$

6.50

4.88

June 30

$

4.88

3.60

$

6.75

5.80

September 30

$

3.65

2.70

$

5.83

4.80

December 31

$

3.01

2.05

$

5.35

3.71

The
Company has not paid a cash dividend on its common stock and does not intend to pay such a dividend in the foreseeable future.

13

Item
6. Selected Financial Data.

Selected Statement of Operations Data:

The following table sets forth selected financial data of the Company for each of the years in the five-year period ended December 31, 2002, which information has been derived from the Companys audited financial statements.
This information should be read in connection with and is qualified in its entirety by the more detailed information in the Companys financial statements under Item 8 below and Item 7, Managements Discussion And Analysis Of
Financial Condition And Results Of Operations.

Year Ended December 31,

2002

2001

2000

1999

1998

Revenues

$

19,099,929

29,894,779

28,489,391

14,020,574

10,591,873

Lease Operating Expense and Production Taxes

9,421,375

8,441,973

6,913,968

3,591,427

2,821,515

Depletion, Depreciation and Amortization

5,452,341

6,844,751

5,953,641

4,743,608

4,094,447

Exploration

1,128,855

4,174,436

2,813,332

1,656,158

6,010,425

General and Administrative

4,467,641

3,134,865

2,518,228

1,989,703

2,399,332

Interest Expense

985,185

1,290,681

4,390,331

2,810,576

1,909,849

Total Costs and Expenses

21,797,476

25,687,242

24,712,518

15,330,062

18,311,421

Gain (Loss) on sale of assets

2,941,062

26,779

307,299

(519,495

)

4,206

Income taxes

88,648

1,487,070

(1,655,032

)





Net Income (Loss)

154,867

2,747,246

5,739,204

(1,828,983

)

(7,715,342

)

Preferred Stock Dividends

639,753

3,002,872

1,193,768

1,249,343

1,255,638

Income (Loss) Applicable to Common Stock

(484,886

)

(255,626

)

4,545,436

(3,078,326

)

(8,970,980

)

Basic Income (Loss) Per Average Common Share

$

(.03

)

(.01

)

.46

(.58

)

(1.71

)

Diluted Income (Loss) Per Average Common Share

$

(.03

)

(.01

)

.35

(.58

)

(1.71

)

Average Common Shares Outstanding Basic

17,908,182

17,351,375

9,903,248

5,288,011

5,243,105

Average Common Shares Outstanding Diluted

17,908,182

17,351,375

13,116,641

5,288,011

5,243,105

December 31,

2002

2001

2000

1999

1998

Selected Balance Sheet Data:

Total Assets

$

80,765,974

82,243,931

65,343,594

56,258,552

44,036,588

Total Long Term Debt

18,500,000

24,500,000

22,965,000

36,953,117

29,500,000

Stockholders Equity

$

46,806,116

47,920,547

32,605,216

6,411,044

4,959,388

Item
7. Managements Discussion and Analysis of Financial Condition and Results of Operations

General

The Company was created by the combination of Patrick Petroleum Company (Patrick) and La/Cal Energy Partners, a partnership in
which it had a controlling interest (La/Cal), in August 1995. The combination was a reverse merger in which the Companys current management gained control of the combined company, renamed it Goodrich Petroleum Corporation and
assumed Patricks New York Stock Exchange listing.

Results of Operations

Year ended December 31, 2002 versus year ended December 31, 2001Total revenues in 2002 amounted to $19,100,000 and were $10,796,000 (36%) lower than total revenues in 2001 due primarily to a 30% decline in

14

production volumes resulting largely from the sale of thirty percent (30%) of Burrwood and West Delta fields on March 12, 2002 and lower
natural gas prices, partially offset by slightly higher oil prices. Oil and gas sales were $18,969,000 for the twelve months ended 2002, compared to $29,542,000 for the twelve months ended December 31, 2001, or $10,573,000 lower due to lower oil and
gas production volumes, primarily the result of the sale of a thirty percent (30%) interest in the Burrwood and West Delta fields. Oil and gas revenues were also reduced during the period due to a majority of the Companys oil and gas
production being shut in temporarily as a result of Hurricane Isidore and Hurricane Lili in September and October 2002. Oil sales were reduced by $274,000 and gas sales were reduced by $739,000 for the year ended December 31, 2002, compared to
reductions of $89,000 for oil sales and $972,000 for gas sales in the year ended December 31, 2001 as a result of settlement of the Companys outstanding oil and gas futures contracts. The Company recorded a gain of $2,941,000 primarily due to
the sale of thirty percent (30%) interest in the Burrwood and West Delta fields for the twelve months ended December 31, 2002, compared to a gain of $27,000 for the twelve months ended December 31, 2001.

The following table reflects the production volumes and
pricing information for the periods presented:

2002

2001

Production

Average Price

Production

Average Price

Gas (Mcf)

2,477,790

$

3.08

3,823,227

$

3.97

Oil (Bbls)

451,564

$

25.09

581,680

$

24.67

Lease
operating expense was $7,757,000 for 2002 compared to $6,576,000 for 2001, or $1,181,000 higher, due primarily to significantly increased costs associated with salt water disposal in the Burrwood and West Delta fields, final billings from the prior
operator of the Companys Second Bayou field, higher well insurance costs and transition costs associated with the Company assuming operations of its oil and gas properties from a contract operator on June 1, 2002, partially offset by the sale
of a thirty percent (30%) working interest in the Burrwood and West Delta fields on March 12, 2002. Work was completed at the end of the second quarter to alleviate higher costs associated with compression and salt water disposal. Production taxes
in 2002 were $1,664,000 compared to $1,866,000 or $202,000 lower due to lower oil and gas sales during 2002. Depletion, depreciation and amortization was $5,452,000 in 2002 versus $6,845,000 in 2001, or $1,393,000 lower, due primarily to lower
production volumes in 2002 versus 2001.

The
Company incurred $1,129,000 of exploration expense in 2002 compared to $4,174,000 in 2001, or $3,045,000 lower, due primarily to dry hole and seismic costs of $-0- and $130,000 respectively in 2002, compared to $1,604,000 and $994,000 respectively
in 2001.

The Company recorded an impairment in
the recorded value of certain oil and gas properties in 2002 in the amount of $342,000 due primarily to a sooner than anticipated depletion of reserves in non-core fields. This compares to an impairment of $1,801,000 recorded in 2001.

General and administrative expenses amounted to $4,468,000 for
the twelve months ended December 31, 2002 versus $3,135,000 in 2001 or $1,333,000 higher, due primarily to legal costs of $983,000 attributable to litigation against the operator and joint owner of the Companys Lafitte field and added salaries
associated with the Company assuming operations from its contract operator.

Interest expense was $985,000 in the twelve months ended December 31, 2002 compared to $1,291,000 in the twelve months ended December 31, 2001, or $306,000 lower, due primarily to lower average debt
outstanding, reflecting debt reduction from proceeds of a property sale, and a lower average effective interest rate for the twelve months ended December 31, 2002. The 2002 amount includes $223,000 of non cash expenses associated with the
amortization of deferred debt financing costs and amortization of the discount associated with the production payment liability recorded in connection with the Lafitte field acquisition. These non-cash expenses totaled $242,000 in 2001.

15

The Company
recorded deferred tax expense (not requiring current cash payment) of $89,000 in 2002 compared to the recording of a deferred tax expense of $1,487,000 in 2001 based primarily on the utilization of net operating loss carryforwards.

Preferred stock dividends were $640,000 in 2002 compared to
$3,003,000 in 2001. In 2002, such amount consisted solely of cash dividends paid on the Companys Series A preferred stock whereas the 2001 amount includes cash dividends paid on the Companys Series A preferred stock in the amount of
$626,000, as well as a non-cash charge related to the conversion of the Companys Series B preferred stock into common stock in the amount of $2,377,000.

Year ended December 31, 2001 versus year ended December 31, 2000 Total revenues in 2001 amounted to $29,895,000 and were
$1,406,000 (5%) higher than total revenues in 2000 due primarily to higher oil and gas sales. Oil and gas sales were $29,542,000 for the twelve months ended 2001, compared to $28,014,000, or $1,528,000 higher due to higher oil and gas production
volumes partially offset by lower oil prices. Oil sales were reduced by $89,000 and gas sales were reduced by $972,000 for the year ended December 31, 2001 compared to reductions of $2,461,000 for oil sales and $441,000 for gas sales in the year
ended December 31, 2000 as a result of settlement of the Companys outstanding futures contracts. The Company recorded a gain on the sale of certain non-core oil and gas properties of $27,000 for the twelve months ended December 31, 2001
compared to a gain of $307,000 for the twelve months ended December 31, 2000.

The following table reflects the production volumes and pricing information for the periods presented:

2001

2000

Production

Average Price

Production

Average Price

Gas (Mcf)

3,823,227

$

3.97

3,394,921

$

3.95

Oil (Bbls)

581,680

$

24.67

571,766

$

25.55

Lease
operating expense was $6,576,000 for 2001 compared to $4,695,000 for 2000, or $1,881,000 higher, due primarily to a full twelve months of costs at Burrwood and West Delta fields in the 2001 period, compared to ten months in the prior period and an
increased number of net properties. Production taxes in 2001 were $1,866,000 compared to $2,219,000 or $353,000 lower due to severance tax exemptions received on certain production in the Burrwood and West Delta fields. Depletion, depreciation and
amortization was $6,845,000 in 2001 versus $5,954,000 in 2000, or $891,000 higher, due to increased oil and gas production.

The Company incurred $4,174,000 of exploration expense in 2001 compared to $2,813,000 in 2000, or $1,361,000 higher, due primarily to dry
hole and seismic costs of $1,604,000 and $994,000 respectively in 2001, compared to $796,000 and $475,000 respectively in 2000.

The Company recorded an impairment in the recorded value of certain oil and gas properties in 2001 in the amount of $1,801,000 due
primarily to a sooner than anticipated depletion of reserves in two non-core fields. This compares to an impairment of $1,835,000 recorded in 2000.

General and administrative expenses amounted to $3,135,000 for 2001 versus $2,518,000 in 2000 with the increase due mostly to higher legal
expenses.

Interest expense was $1,291,000 in the
twelve months ended December 31, 2001 compared to $4,390,000 in the twelve months ended December 31, 2000, or $3,099,000 lower, due primarily to lower average debt outstanding and a lower average effective interest rate for the twelve months ended
December 31, 2001. The 2001 amount includes $242,000 of non cash expenses associated with the amortization of deferred debt financing costs and amortization of the discount associated with the production payment liability recorded in connection with
the Lafitte field acquisition. The 2000 amount includes $919,000 of non cash expenses associated with the amortization of financing costs and debt discount in connection with the September 1999 private placement and amortization of the discount
associated with the production payment liability recorded in connection with the Lafitte field acquisition.

16

The Company
recorded deferred tax expense (not requiring cash payment) of $1,487,000 in 2001 compared to the recording of a deferred tax benefit of $1,655,000 in 2000.

During 2001 the Company paid dividends of $626,000 on its Series A preferred stock. Also in 2001, the Company exchanged each share of its
Series B preferred stock for 1.8 shares of its common stock and recorded a conversion premium on the income statement as dividends, of $2,377,000 to reflect the excess of the 1.8 conversion factor over the terms of the original preferred stock
issuance. For the period ended December 31, 2000, the Company paid an aggregate of approximately $1.8 million of dividend arrearages and $580,000 of regular quarterly (third and fourth quarter 2000) dividends on its outstanding series of preferred
stock. At December 31, 2001 and 2000, the Company was current as to dividends on its preferred stock. The Company also accrued non-cash dividends on its GoodrichLouisiana Series A Preferred units, prior to conversion, of $38,000 that is
reflected as preferred dividends of subsidiary in the statement of operations for the 2000 period.

Liquidity and Capital Resources

Net cash provided by operating activities was $5,349,000 or 66% lower due primarily to lower production volumes, the majority of which was
due to the sale of thirty percent (30%) of the Burrwood and West Delta fields in 2002, compared to $15,790,000 in 2001 and $12,641,000 in 2000. The accompanying consolidated statements of cash flows identify major differences between net income
(loss) and net cash provided by operating activities for each of the years presented.

Net cash provided by investing activities amounted to $4,743,000 consisting of $8,079,000 of capital expenditures and $12,823,000 in proceeds from the sale of oil and gas properties in 2002 compared to
net cash used in investing activities of $31,846,000 in 2001 and $15,881,000 in 2000. In 2002 the Company participated in the drilling of only two wells, whereas in 2001, a total of seven wells were drilled. Net cash used in investing activities for
2001 consists of capital expenditures of $32,253,000 and proceeds from the sale of oil and gas properties and equipment of $407,000. Net cash used in investing activities for the twelve months ended December 31, 2000, reflects capital expenditures
totaling $15,142,000, cash paid in connection with the acquisition of oil and gas properties of $1,199,000 and proceeds from the sale of oil and gas properties of $460,000. For 2003, the Company anticipates making capital expenditures totaling
approximately $20 million, which will be primarily directed toward the drilling of up to fifteen gross wells. The Company expects to finance its capital expenditures out of operating cash flow and available bank credit, as further described below.

Net cash used in financing activities was
$6,989,000 in 2002 compared to $12,772,000 provided in 2001 and $842,000 provided in 2000. The 2002 amounts consist of pay downs by the Company under its line of credit of $13,500,000. The 2002 amounts also include proceeds from bank borrowings of
$7,500,000, preferred stock dividends of $640,000 and the exercise of employee stock options of $28,000. The 2002 amount also includes production payments of $378,000. The 2001 amount consists of proceeds from the issuance of common stock of
$15,000,000 and pay downs by the Company under its line of credit of $13,690,000. The 2001 amount also includes proceeds from bank borrowings of $15,225,000, the payment of debt financing and public offering costs of $1,984,000, changes in
restricted cash of $799,000, and production payments of $545,000. In addition, the 2001 amount includes preferred stock dividends of $626,000 and proceeds from the exercise of stock warrants and employee stock options of $180,000 and $12,000,
respectively. The 2000 amount includes proceeds from the issuance of common stock of $9,150,000 and paydowns by the Company under its line of credit of $4,125,000. The 2000 amount includes preferred stock dividends of $2,308,000, changes in
restricted cash of $1,240,000 and proceeds from the exercise of stock purchase warrants and director and employee stock options of $451,000. The 2000 amount also includes production payments of $653,000 and payment of debt and equity financing costs
of $432,000.

Credit Facility

On November 9, 2001 the Company established
a $50,000,000 credit facility with BNP Paribas, with an initial borrowing base of $25,000,000. The current borrowing base of $23,000,000 will remain effective until the

17

next borrowing base redetermination, which is scheduled to be made on or before March 31, 2003. Interest on borrowings will accrue at a rate
calculated, at the option of the Company, as either the BNP Paribas base rate plus 0.00% to 0.50%, or LIBOR plus 1.50%2.50%, depending on borrowing base utilization. Interest on LIBOR-rate borrowings is due and payable on the last day of its
respective interest period. Accrued interest on each base-rate borrowing is due and payable on the last day of each quarter. The credit facility will mature on November 8, 2004. The credit facility requires that the Company pay a 0.375% per annum
commitment fee, payable in quarterly installments based on the Companys borrowing base utilization. Prior to maturity, no payments are required so long as the maximum borrowing base amount exceeds the amounts outstanding under the credit
facility. The credit facility requires the Company to monitor tangible net worth and maintain certain financial statement ratios at certain levels. Substantially all the Companys assets are pledged to secure the credit facility. Borrowings
under the credit facility amounted to $18,500,000 at December 31, 2002, and were subsequently increased to $20,000,000 as of March 15, 2003.

Burrwood and West Delta Field Performance Bond and Escrow Account

In connection with the March 2, 2000 Burrwood and West Delta fields acquisition, the Company secured a
performance bond and established an escrow account to be used for the payment of obligations associated with the plugging and abandonment of the wells, salvage and removal of platforms and related equipment, and the site restoration of the fields.
The fully funded escrow account in the amount of $2,039,000 is shown on the Balance Sheet as restricted cash.

Contractual Obligations and GuaranteesThe Company is obligated to make future cash payments under its borrowing agreements.
Total principal payments due after 2002 under such contractual obligations are shown below.

Amount Due

(Millions of dollars)

Total

2003

2004-2006

2007-2008

After 2008

Long-term debt

$

18.5



18.5





Production Payment

$

1.2

0.5

0.7





Accounting Matters

The
Company adopted Statement of Financial Accounting Standards (SFAS) No. 141, Business Combinations (SFAS No. 141) immediately upon release and SFAS No. 142, Goodwill and Other Intangible Assets
(SFAS No. 142) on January 1, 2002. SFAS No. 141 requires that all business combinations be accounted for under the purchase method of accounting and that certain acquired intangible assets in a business combination be recognized and
reported as assets apart from goodwill. SFAS No. 142 requires that amortization of goodwill be replaced with periodic tests of the goodwills impairment at least annually in accordance with the provisions of SFAS No. 142 and that intangible
assets other than goodwill be amortized over their useful lives. The Company does not have any identified intangible assets nor any goodwill as of December 31, 2002 or December 31, 2001. The adoption of SFAS No. 141 and 142 had no significant impact
on the Companys financial statements.

In
July 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations. SFAS No. 143 requires the Company to record a liability equal to the fair value of the estimated cost to retire an asset. The asset retirement liability
must be recorded in the periods in which the obligation meets the definition of a liability, which is generally when the asset is placed in service. When the liability is initially recorded, the Company will increase the carrying amount of the
related long-lived asset by an amount equal to the original liability. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related long-lived asset. Upon adoption of SFAS
No. 143 on January 1, 2003, the Company will recognize transition adjustments for existing asset retirement obligations, long-lived assets and accumulated depreciation, all net of related income tax effects, as the cumulative effect of a change in
accounting principle. After adoption, any difference between costs incurred upon settlement of an asset retirement obligation and the recorded liability

18

will be recognized as a gain or loss in the Companys earnings. The Company is currently unable to determine the effect of adopting SFAS
No. 143 on its financial statements.

In October
2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, which supercedes SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of, and the accounting and
reporting provisions of APB Opinion No. 30, Reporting the Results of OperationsReporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual, and Infrequently Occurring Events and Transactions. The Company adopted
the provision of SFAS No. 144 effective January 1, 2002. The adoption of SFAS No. 144 had no impact on the Company.

The Company adopted Emerging Issues Task Force (EITF) Issue 02-3 in the fourth quarter 2002. This consensus requires that the results of
energy trading activities be recorded on a net margin basis. The adoption had no impact on the Companys financial statements.

In November 2002, the FASB issued Interpretation No. 45, Guarantors Accounting and Disclosure Requirement for Guarantees, Including
Indirect Guarantees of Indebtedness to Others, an Interpretation of FASB Statements No. 5, 57 and 107 and a rescission of FASB Interpretation No. 34. This Interpretation elaborates on the disclosures to be made by a guarantor in its interim and
annual financial statements about its obligations under guarantees issued. The Interpretation also clarifies that a guarantor is required to recognize, at inception of a guarantee, a liability for the fair value of the obligation undertaken. The
initial recognition and measurement provisions of the Interpretation are applicable to guarantees issued or modified after December 31, 2002 and are not expected to have a material effect on the Companys financial statements. The disclosure
requirements are effective for financial statements of interim and annual periods ending after December 15, 2002.

In December 2002, the FASB issued SFAS No. 148, Accounting for Stock-Based Compensation  Transition and Disclosure, an amendment of
FASB Statement No. 123. This Statement amends FASB Statement No. 123, Accounting for Stock-Based Compensation, to provide alternative methods of transition for a voluntary change to the fair value method of accounting for stock-based employee
compensation. In addition, this Statement amends the disclosure requirements of Statement No. 123 to require prominent disclosures in both annual and interim financial statements. Certain of the disclosure modifications are required for fiscal years
ending after December 15, 2002.

Critical
accounting policiesIn preparing the financial statements of the Company in accordance with accounting principles generally accepted in the United States of America, management must make a number of estimates and assumptions related to the
reporting of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. Application of certain of the Companys accounting policies requires a significant amount of estimates. These accounting policies
are described below.



Proved oil and natural gas reservesProved reserves are defined by the Securities and Exchange Commission (SEC) as those volumes of crude oil,
condensate, natural gas liquids and natural gas that geological and engineering data demonstrate with reasonable certainty are recoverable from known reservoirs under existing economic and operating conditions. Proved developed reserves are volumes
expected to be recovered through existing wells with existing equipment and operating methods. Although the Companys external engineers are knowledgeable of and follow the guidelines for reserves as established by the SEC, the estimation of
reserves requires the engineers to make a significant number of assumptions based on professional judgment. Estimated reserves are often subject to future revision, certain of which could be substantial, based on the availability of additional
information, including: reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes and other economic factors. Changes in oil and natural gas prices can lead to a decision to start-up
or shut-in production, which can lead to revisions to reserve quantities. Reserve revisions inherently lead to adjustments of depreciation rates utilized by the

19

Company. The Company cannot predict the types of reserve revisions that will be required in future periods.



Successful efforts accountingThe Company utilizes the successful efforts method to account for exploration and development expenditures. Unsuccessful
exploration wells are expensed and can have a significant effect on operating results. Successful exploration drilling costs and all development capital expenditures are capitalized and systematically charged to expense using the units of production
method based on proved developed oil and natural gas reserves as estimated by engineers. The Company also uses proved developed reserves for calculating the amount of expense to recognize for future estimated dismantlement and abandonment costs.



Impairment of propertiesThe Company continually monitors its long-lived assets recorded in Property, Plant and Equipment in the Consolidated Balance
Sheet to make sure that they are presented fairly and accurately. The Company must evaluate its properties for potential impairment when circumstances indicate that the carrying value of an asset could exceed its fair value. Performing these
evaluations requires a significant amount of judgment since the results are based on estimated future events. Such events include a projection of future oil and natural gas sales prices, an estimate of the ultimate amount of recoverable oil and
natural gas reserves that will be produced from a field, the timing of this future production, future costs to produce the oil and natural gas, and future inflation levels. The need to test a property for impairment can be based on several factors,
including a significant reduction in sales prices for oil and/or natural gas, unfavorable adjustments to reserves, or other changes to contracts, environmental regulations or tax laws. The Company cannot predict the amount of impairment charges that
may be recorded in the future.



Income taxesThe Company is subject to income and other related taxes in areas in which it operates. When recording income tax expense, certain estimates
are required by management due to timing and the impact of future events on when income tax expenses and benefits are recognized by the Company. The Company has recorded a deferred tax asset relating primarily to its tax operating loss
carryforwards. The Company periodically evaluates its deferred tax asset to determine the likelihood of its realization. A valuation allowance has been recorded for the deferred tax asset to the extent that they are not likely to be realized based
on managements estimation.

Item
7A. Quantitative and Qualitative Disclosures About Market Risk

Commodity Hedging Activity

The Company enters into futures contracts or other hedging agreements from time to time to manage the commodity price risk for a portion
of its production. The Company considers these to be hedging activities and, as such, monthly settlements on these contracts are reflected in its oil and natural gas sales. The Companys strategy, which is administered by the Hedging Committee
of the Board of Directors, and reviewed periodically by the entire Board of Directors, has been to hedge between 30% and 70% of its production. A portion of the Companys hedging arrangements are in the form of costless collars, whereby a floor
and a ceiling are fixed. It is the Companys belief that the benefits of the downside protection afforded by these costless collars outweigh the costs incurred by losing potential upside when commodity prices increase. The remainder of the
hedges utilized by the Company are in the form of fixed price swaps, where the Company receives a fixed price and pays a floating price. On January 1, 2001, the Company adopted a formal policy with respect to hedging arrangements in accordance with
accounting pronouncements. The Company does not expect its hedging policy or future hedging practice to differ materially from its historical practice. The Company has no plans to engage in speculative activity not supported by production.

The Companys futures contract agreements
provide for separate contracts tied to the New York Mercantile Exchange (NYMEX) light sweet crude oil and natural gas futures contracts. The contracts contain either specific prices or price ranges known as collars that are
settled monthly based on the differences between the contract price or price ranges and the average NYMEX prices for each month applied to the related contract

20

volumes. To the extent the average NYMEX price exceeds the contract price, the Company pays the difference, and to the extent the contract
price exceeds the average NYMEX price, the Company receives the difference.

As of December 31, 2002, the Companys open forward position on its outstanding natural gas and crude oil hedging contracts, all of which were with BNP Paribas, were as follows:

Natural Gas

3000 MMBtu per day swap at $3.50 for January 2003 through February
2003; and

3000 MMBtu per day with a no cost collar of $3.50 and $5.19 per Mmbtu for January through December 2003; and

3000 MMBtu per day swap at $4.06 for January 2003 through December 2003.

Crude Oil

300 barrels of oil per day swap at $28.80 for January 2003 through February 2003; and

200 barrels of oil per day swap at $29.07 for January 2003 through February 2003; and

100 barrels of oil per day swap at $28.95 for January 2003 through February 2003; and

300 barrels of oil per day swap at $27.45 for March 2003 through May 2003; and

200 barrels of oil per day swap at $29.08 for March 2003 through May 2003

The fair value of the natural gas and oil hedging contracts in place at December 31, 2002, resulted, in a liability of $1,108,000.

The Company entered into the following crude oil
hedging contracts, all of which were with BNP Paribas, subsequent to December 31, 2002.

300 barrels of oil per day swap at $32.58 for March 2003 through May 2003; and

300 barrels of oil per
day swap at $28.47 for June 2003 through December 2003; and

200 barrels of oil per day swap at $29.32 for June 2003
through December 2003; and

200 barrels of oil per day swap at $29.97 for June 2003 through December 2003

Price fluctuations and the volatile nature of markets

Despite the measures the Company has taken
to attempt to control price risk, it remains subject to price fluctuations for oil and natural gas sold in the spot market. Prices received for natural gas sold in the spot market are volatile due primarily to seasonality of demand and other factors
beyond the Companys control. Oil and natural gas prices can change dramatically primarily as a result of the balance between supply and demand. The Companys average natural gas price received for the year ending December 31, 2002, was
$3.08 per Mcf, down from $3.97 per Mcf in 2001 and down from $3.95 per Mcf in 2000. The Companys average oil price received for the year ended December 31, 2002, was $25.09, up from an average price received of $24.67 in 2001 and down from an
average price received of $25.55 in 2000. There can be no assurance that prices will not decline from current levels. Declines in domestic oil and natural gas prices could have a material adverse effect on the Companys financial position,
results of operations and quantities of reserves recoverable on an economic basis. Based on oil and gas pricing in effect at December 31, 2002, a hypothetical 2% increase or decrease in oil and gas pricing would not have had a material effect on the
Companys financial statements.

Debt and
debt-related derivatives

Subsequent to
December 31, 2002, the Company entered into three separate interest rate swaps with BNP Paribas over a three year period. The first interest rate swap, which has an effective date of February 26, 2003 and a maturity date of February 26, 2004 is for
$18,000,000 with a LIBOR swap rate of 1.53%. The second

21

interest rate swap, which has an effective date of February 26, 2004 and a maturity date of November 8, 2004, is for $18,000,000 with a LIBOR
swap rate of 2.25%. The third interest rate swap, which has an effective date of November 8, 2004 and a maturity date of February 26, 2006, is for $18,000,000 with a LIBOR swap rate of 3.46%.

Subsequent to implementing the interest rate swap, interest on
the Companys senior credit facility with BNP Paribas will accrue at a rate calculated at the LIBOR swap rate plus 1.5%2.5%, depending on borrowing base utilization, with respect to the notional debt amount of $18,000,000.

For debt over and above the $18,000,000 hedged under the
interest rate swaps, the Company is exposed to interest rate risk on its short-term and long-term debt with variable interest rates. Based on the overall interest rate exposure on variable rate debt at December 31, 2002, a hypothetical 2% increase
in the interest rates would increase interest expense by approximately $365,000.

Disclosure Regarding Forward-Looking Statements

This Annual Report on Form 10-K includes forward-looking statements within the meaning of Section 27A of the Securities Act of
1933, as amended (the Securities Act) and Section 21E of the Securities Exchange Act of 1934, as amended (the Exchange Act). All statements other than statements of historical facts included in this Annual Report on Form 10-K
regarding reserve estimates, planned capital expenditures, future oil and gas production and prices, future drilling activity, the Companys financial position, business strategy and other plans and objectives for future operations, are
forward-looking statements. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct. Reserve engineering is a
subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological
interpretation and judgment. As a result, estimates made by different engineers often vary from one another. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revisions of such estimates and
such revisions could change the schedule of any further production and development drilling. Accordingly, reserve estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. Additional important
factors that could cause actual results to differ materially from the Companys expectations include changes in oil and gas prices, changes in regulatory or environmental policies, production difficulties, transportation difficulties and future
drilling results. All subsequent written and oral forward-looking statements attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by such factors.

22

Item 8. Financial Statements and Supplementary Data

INDEPENDENT AUDITORS REPORT

The Board of Directors and Stockholders

Goodrich Petroleum Corporation:

We have audited the accompanying consolidated balance sheets of Goodrich Petroleum Corporation and Subsidiaries as of December 31, 2002
and 2001, and the related consolidated statements of operations, cash flows and stockholders equity and comprehensive income for each of the years in the three-year period ended December 31, 2002. These consolidated financial statements are
the responsibility of the Companys management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of
America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the
amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management as well as evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Goodrich Petroleum Corporation and Subsidiaries as of December 31, 2002 and 2001, and the
results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note B to the consolidated financial
statements, effective January 1, 2001, the Company changed its method of accounting for derivative instruments and hedging activities.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY AND
COMPREHENSIVE INCOME

Years Ended December
31, 2002, 2001 and 2000

Series A

Preferred Stock

Series B

Preferred Stock

Common Stock

Additional

Paid-In

Capital

Accumulated

Deficit

Accumulated

Other Comprehensive

Income-

Total

Stockholders

Equity

Balance at January 1, 2000

796,318

$

796,318

665,759

$

665,759

5,417,171

$

1,083,434

$

18,156,114

$

(14,290,581

)

$



$

6,411,044

Net Income















5,739,204



5,739,204

Total Comprehensive Income



















5,739,204

Issuance of Common Stock









2,533,333

506,667

8,643,333





9,150,000

Conversion of preferred stock of subsidiary to common stock









1,547,665

309,533

2,411,956





2,721,489

Exercise of director stock option









12,500

2,500

7,375





9,875

Conversion of notes payable









3,295,647

659,130

9,751,719





10,410,849

Preferred stock dividends















(2,308,011

)



(2,308,011

)

Exercise of common stock purchase warrants









252,022

50,403

198,919





249,322

Exercise of Employee Stock Options









245,698

49,140

142,304





191,444

Director Stock Grant









6,000

1,200

28,800





30,000

Conversion of Series B Preferred Stock to Common Stock





(4,920

)

(4,920

)

5,486

1,097

3,823







Conversion of Series A Preferred Stock to Common Stock

(4,350

)

(4,350

)





3,398

680

3,670







Balance at December 31, 2000

791,968

$

791,968

660,839

$

660,839

13,318,920

$

2,663,784

$

39,348,013

$

(10,859,388

)

$



$

32,605,216

Net Income















2,747,246



2,747,246

Cumulative Effect of Accounting Change, net of tax

















(2,535,469

)

(2,535,469

)

Net Derivative Gain, net of tax

















1,797,336

1,797,336

Reclassification Adjustment, net of tax

















746,583

746,583

Total Comprehensive Income



















2,755,696

Issuance of Common Stock









3,000,000

600,000

12,469,170





13,069,170

Preferred stock dividends















(626,331

)



(626,331

)

Exercise of common stock purchase warrants









375,296

75,059

105,174





180,233

Exercise of Employee Stock Options









7,500

1,500

10,063





11,563

Conversion of Series B Preferred Stock to Common Stock





(660,839

)

(660,839

)

1,189,510

237,902

317,937





(105,000

)

Director Stock Grant









5,130

1,026

28,974





30,000

Balance at December 31, 2001

791,968

$

791,968



$



17,896,356

$

3,579,271

$

52,279,331

$

(8,738,473

)

$

8,450

$

47,920,547

Net Income















154,867



154,867

Cumulative Effect of Accounting Change, net of tax





















Net Derivative Gain, net of tax

















(1,345,763

)

(1,345,763

)

Reclassification Adjustment, net of tax

















658,218

658,218

Total Comprehensive Income



















(532,678

)

Preferred stock dividends















(639,753

)



(639,753

)

Exercise of common stock purchase warrants





















Exercise of Employee Stock Options









10,667

2,133

25,867





28,000

Conversion of Series B Preferred Stock to Common Stock





















Director Stock Grant









7,302

1,460

28,540





30,000

Balance at December 31, 2002

791,968

$

791,968



$



17,914,325

$

3,582,864

$

52,333,738

$

(9,223,359

)

$

(679,095

)

$

46,806,116

See notes
to consolidated financial statements

27

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2002

NOTE ADescription of Business

The Company is in the primary business of exploration and
production of crude oil and natural gas. The Companys subsidiaries have interests in such operations in four states, primarily in Louisiana and Texas.

NOTE BSummary of Significant Accounting Policies

Principles of ConsolidationThe consolidated financial statements include the financial statements of Goodrich Petroleum
Corporation and its wholly-owned subsidiaries. Significant intercompany balances and transactions have been eliminated in consolidation.

Revenue RecognitionRevenues from the production of crude oil and natural gas properties in which the Company has an interest
with other producers are recognized on the entitlements method. The Company records an asset or liability for natural gas balancing when the Company has purchased or sold more than its working interest share of natural gas production, respectively.
At December 31, 2002 and 2001, the assets and liabilities for gas balancing were immaterial. Differences between actual production and net working interest volumes are routinely adjusted. These differences are not significant.

Property and EquipmentThe Company uses the
successful efforts method of accounting for exploration and development expenditures. Leasehold acquisition costs are capitalized. When proved reserves are found on an undeveloped property, leasehold cost is reclassified to proved properties.
Significant undeveloped leases are reviewed periodically, and a valuation allowance is provided for any estimated decline in value. Cost of all other undeveloped leases is amortized over the estimated average holding period of the leases.

Costs of exploratory drilling are initially
capitalized, but if proved reserves are not found, the costs are subsequently expensed. All other exploratory costs are charged to expense as incurred. Development costs are capitalized, including the cost of unsuccessful development wells.

The Company recognizes an impairment when the
net of future cash inflows expected to be generated by an identifiable long-lived asset and cash outflows expected to be required to obtain those cash inflows is less than the carrying value of the asset. The Company performs this comparison for its
oil and gas properties on a field-by-field basis using the Companys estimates of future commodity prices. The amount of such loss is measured based on the difference between the discounted value of such net future cash flows and the carrying
value of the asset. The Company recorded such impairments in 2002, 2001 and 2000 in the amounts of $342,000, $1,801,000 and $1,835,000 respectively. The impairments were generally the result of certain non-core fields depleting earlier than
anticipated.

Depreciation and depletion of
producing oil and gas properties are provided under the unit-of-production method. Proved developed reserves are used to compute unit rates for unamortized tangible and intangible development costs, and proved reserves are used for unamortized
leasehold costs. Estimated dismantlement, abandonment, and site restoration costs, net of salvage value, are considered in determining depreciation and depletion provisions.

Gains and losses on disposals or retirements that are significant or include an entire depreciable or
depletable property unit are included in income. All other dispositions, retirements, or abandonments are reflected in accumulated depreciation, depletion, and amortization.

28

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)

December 31, 2002

Cash
and Cash EquivalentsCash and cash equivalents include cash on hand, demand deposit accounts and temporary cash investments with maturities of ninety days or less at date of purchase.

Income TaxesThe Company follows the provisions of
SFAS No. 109, Accounting for Income Taxes, which requires income taxes be accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the
financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to
taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment
date.

Earnings Per ShareBasic
income per common share is computed by dividing net income available for common stockholders, for each reporting period by the weighted average number of common shares outstanding during the period. Diluted income per common share is computed by
dividing net income available for common stockholders for each reporting period by the weighted average number of common shares outstanding during the period, plus the effects of potentially dilutive common shares.

Derivative Instruments and Hedging ActivitiesThe
Company utilizes derivative instruments such as futures, forwards, options, collars and swaps for purposes of hedging its exposure to fluctuations in the price of crude oil and natural gas and to hedge its exposure to changing interest rates.

Effective January 1, 2001, the Company adopted
Statement of Financial Accounting Standard (SFAS 133), Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS 138. See also Note K for further information about the Companys derivative instruments. In accordance with
the transition provisions of SFAS 133, the Company recorded a cumulative adjustment of $2,535,000 (net of $1,365,000 in income taxes) in accumulated other comprehensive income to recognize at fair value all derivatives that were designated as cash
flow hedging instruments. There was no cumulative effect on earnings. The fair value of a derivative instrument is recognized as an asset or liability in the Companys Consolidated Balance Sheet. Upon entering into a derivative contract, the
Company may designate the derivative as either a fair value hedge or a cash flow hedge, or decide that the contract is not a hedge, and thenceforth, mark the contract to market through earnings. The Company documents the relationship between the
derivative instrument designated as a hedge and the hedged items, as well as its objective for risk management and strategy for use of the hedging instrument to manage the risk. Derivative instruments designated as fair value or cash flow hedges are
linked to specific assets and liabilities or to specific firm commitments or forecasted transactions. The Company assesses at inception, and on an ongoing basis, whether a derivative instrument used as a hedge is highly effective in offsetting
changes in the fair value or cash flows of the hedged item. A derivative that is not a highly effective hedge does not qualify for hedge accounting. Changes in the fair value of a qualifying fair value hedge are recorded in earnings along with the
gain or loss on the hedged item. Changes in the fair value of a qualifying cash flow hedge are recorded in other comprehensive income, until earnings are affected by the cash flows of the hedged item. When the cash flow of the hedged item is
recognized in the Statement of Income, the fair value of the associated cash flow hedge is reclassified from other comprehensive income into earnings.

Ineffective portions of a cash flow hedging derivatives change in fair value are recognized currently in earnings. If a derivative
instrument no longer qualifies as a cash flow hedge, hedge accounting is discontinued and the gain or loss that was recorded in other comprehensive income is recognized immediately in earnings.

29

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)

December 31, 2002

For the
year ended December 31, 2000, prior to the adoption of SFAS No. 133, gains and losses from derivatives designated as hedges of sales were reported on the Statement of Income as an increase or reduction of oil and gas sales in the period related to
the actual sale of product. Premiums paid on hedging contracts were amortized over the life of the contracts as a reduction to oil and gas sales.

Stock Based CompensationThe Company uses SFAS No. 123, Accounting for Stock-Based Compensation, which permits entities to
recognize as expense, over the vesting period, the fair value of all stock-based awards on the date of grant. Alternatively, SFAS No. 123 also allows entities to continue to apply the provisions of APB Opinion No. 25, Accounting for Stock Issued to
Employees, and provide pro forma net income and pro forma earnings per share and other disclosures for employee stock option grants made in 1995 and future years as if the fair-value-based method defined in SFAS No. 123 had been applied. The Company
has elected to continue to apply the provisions of APB Opinion No. 25 and provide the disclosure provisions of SFAS No. 123. For stock based compensation that vests on a prorata basis where the award is fixed at the grant date, the Company has
elected to amortize those costs using straight line method over the life of the award.

The Company applies APB Opinion No. 25 in accounting for its plans and, accordingly, no compensation cost has been recognized for its stock options in the financial statements. Had the Company
determined compensation cost based on the fair value at the grant date for its stock options under SFAS No. 123, the Companys net income (loss) would have been reduced to the pro forma amounts indicated below:

2002

2001

2000

Net Income (loss)

As reported

$

154,867

$

2,747,246

5,739,204

Pro forma

(792,230

)

2,063,595

5,040,410

Income (loss) applicable to

As reported

(484,886

)

(255,626

)

4,545,436

common stock

Pro forma

(1,431,983

)

(939,277

)

3,846,642

Basic income (loss)

per average common share

As reported

(0.03

)

(0.01

)

0.46

Pro forma

(0.08

)

(0.05

)

0.39

Diluted income (loss)

per average common share

As reported

(0.03

)

(0.01

)

0.35

Pro forma

(0.08

)

(0.05

)

0.29

Commitments and ContingenciesLiabilities for loss contingencies, including environmental remediation costs, arising from claims, assessments, litigation, fines and penalties, and other sources are recorded when it is
probable that a liability has been incurred and the amount of the assessment and/or remediation can be reasonably estimated. Recoveries from third parties, which are probable of realization, are separately recorded, and are not offset against the
related environmental liability.

Use of
EstimatesManagement of the Company has made a number of estimates and assumptions relating to the reporting of assets and liabilities and the disclosure of contingent assets and liabilities to prepare these consolidated financial
statements in conformity with accounting principles generally accepted in the United States of America. Actual results could differ from those estimates.

Accounting Matters The Company adopted Statement of Financial Accounting Standards (SFAS) No. 141, Business
Combinations (SFAS No. 141) immediately upon release and SFAS No. 142, Goodwill and Other Intangible Assets (SFAS No. 142) on January 1, 2002. SFAS No. 141 requires that all business combinations be
accounted for under the purchase method of accounting and that certain acquired intangible

30

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)

December 31, 2002

assets in a business combination be recognized and reported as assets apart from goodwill. SFAS No. 142 requires that amortization of
goodwill be replaced with periodic tests of the goodwills impairment at least annually in accordance with the provisions of SFAS No. 142 and that intangible assets other than goodwill be amortized over their useful lives. The Company does not
have any identified intangible assets nor any goodwill as of December 31, 2002 or December 31, 2001. The adoption of SFAS No. 141 and 142 had no significant impact on the Companys financial statements.

In July 2001, the FASB issued SFAS No. 143, Accounting for
Asset Retirement Obligations. SFAS No. 143 requires the Company to record a liability equal to the fair value of the estimated cost to retire an asset. The asset retirement liability must be recorded in the periods in which the obligation meets
the definition of a liability, which is generally when the asset is placed in service. When the liability is initially recorded, the Company will increase the carrying amount of the related long-lived asset by an amount equal to the original
liability. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related long-lived asset. Upon adoption of SFAS No. 143 on January 1, 2003, the Company will recognize
transition adjustments for existing asset retirement obligations, long-lived assets and accumulated depreciation, all net of related income tax effects, as the cumulative effect of a change in accounting principle. After adoption, any difference
between costs incurred upon settlement of an asset retirement obligation and the recorded liability will be recognized as a gain or loss in the Companys earnings. The Company is currently unable to determine the effect of adopting FAS No. 143
on its financial statements.

In October 2001,
the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, which supercedes SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of, and the accounting and
reporting provisions of APB Opinion No. 30, Reporting the Results of OperationsReporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual, and Infrequently Occurring Events and Transactions. The Company adopted
the provision of SFAS No. 144 effective January 1, 2002. The adoption of SFAS No. 144 had no impact on the Company.

The Company adopted Emerging Issues Task Force (EITF) Issue 02-3 in the fourth quarter 2002. This consensus requires that the results of
energy trading activities be recorded on a net margin basis. The adoption had no impact on the Companys financial statements.

In November 2002, the FASB issued Interpretation No. 45, Guarantors Accounting and Disclosure Requirement for Guarantees, Including
Indirect Guarantees of Indebtedness to Others, an interpretation of FASB Statements No. 5, 57 and 107 and a rescission of FASB Interpretation No. 34. This Interpretation elaborates on the disclosures to be made by a guarantor in its interim and
annual financial statements about its obligations under guarantees issued. The Interpretation also clarifies that a guarantor is required to recognize, at inception of a guarantee, a liability for the fair value of the obligation undertaken. The
initial recognition and measurement provisions of the Interpretation are applicable to guarantees issued or modified after December 31, 2002 and are not expected to have a material effect on the Companys financial statements. The disclosure
requirements are effective for financial statement of interim and annual periods ending after December 15, 2002.

In December 2002, the FASB issued SFAS No. 148, Accounting for Stock-Based Compensation  Transition and Disclosure, an amendment of
FASB Statement No. 123. This Statement amends FASB Statement No. 123, Accounting for Stock-Based Compensation, to provide alternative methods of transition for a voluntary change to the fair value method of accounting for stock-based employee
compensation. In addition, this Statement amends the disclosure requirements of Statement No. 123 to require prominent disclosures in both

31

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)

December 31, 2002

annual and interim financial statements. Certain of the disclosure modifications are required for fiscal years ending after December 15, 2002
and are included in the notes to these consolidated financial statements.

NOTE CSale of Oil and Gas Properties to Related Party

On March 12, 2002, the Company, in an effort to monetize a portion of the value created in its Burrwood and West Delta fields and enhance its liquidity position, completed the sale of a thirty percent
(30%) working interest in the existing production and shallow rights, and a fifteen percent (15%) working interest in the deep rights below 10,600 feet, in its Burrwood and West Delta fields for $12 million to Malloy Energy Company, LLC led by
Patrick E. Malloy, III and participated in by Sheldon Appel, both members of the Companys Board of Directors (Mr. Malloy is now Chairman of the Companys Board of Directors), as well as Josiah Austin, who subsequently became a member of
the Companys Board of Directors. The sale price was determined by discounting the present value of the acquired interest in the fields proved, probable and possible reserves using prevailing oil and gas prices. The Company retained an
approximate sixty-five percent (65%) working interest in the existing production and shallow rights, and a thirty-two and one-half percent (32.5%) working interest in the deep rights after the close of the transaction. In conjunction with the sale,
the investor group provided a $7.7 million line of credit. The $7.7 million line of credit, which reduced to $5.0 million on January 1, 2003, is subordinate to the Companys senior credit facility and can be used for acquisitions, drilling,
development and general corporate purposes until December 31, 2004. The investor group retains the option, during the two-year period, to convert the amount outstanding under the credit line, and/or provide cash on any unused credit to a maximum of
$7.7 million through December 31, 2002, reduced to $5.0 million after December 31, 2002, into working interests in any acquisition(s) the Company may make in Louisiana prior to January 1, 2005. The conversion of the credit facility will be on a
pro-rata basis with the Companys interest and may not exceed a maximum of $7.7 million reduced to $5.0 million after December 31, 2002 or thirty percent (30%) of any potential acquisition(s). To date, no borrowings have been made under the
credit facility.

The Company recorded a
non-recurring gain of approximately $2.4 million in the first quarter of 2002 as a result of the sale. The proceeds were used to reduce outstanding debt under its senior credit facility.

NOTE DPublic Offering

On February 1, 2001, the Company completed a public offering of 3,000,000 shares of its common stock at $5.00 per share resulting in net
proceeds of approximately $13.2 million to the Company. The Company used the proceeds from the offering along with other available funds to reduce outstanding debt under its senior credit facility by approximately $13.7 million.

NOTE EExchange of Series B Preferred Stock

Prior to the public offering, the Company reached an
agreement with all of the holders of its Series B preferred stock to exchange each share of Series B preferred stock for 1.8 shares of its common stock. Concurrent with the closing of the public offering, the Company exchanged all 660,839 shares of
its Series B preferred stock into 1,189,510 shares of common stock. In connection with the conversion of the Series B preferred stock, a conversion premium in the amount of $2,377,000 was recorded to reflect the excess of the 1.8:1.0 conversion
factor over the terms of the original preferred stock issuance. This one-time, non-cash charge was reflected as a preferred stock dividend to arrive at net income applicable to common stock and did not have an affect on total stockholders
equity.

On
November 9, 2001 the Company established a $50,000,000 credit facility with BNP Paribas, with an initial borrowing base of $25,000,000. The current borrowing base of $23,000,000 will remain effective until the next borrowing base redetermination,
which is scheduled to be made on or before March 31, 2003. Interest on borrowings will accrue at a rate calculated, at the option of the Company, as either the BNP Paribas base rate plus 0.00% to 0.50%, or LIBOR plus 1.50%2.50%, depending on
borrowing base utilization. Interest on LIBOR-rate borrowings is due and payable on the last day of its respective interest period. Accrued interest on each base-rate borrowing is due and payable on the last day of each quarter. The credit facility
will mature on November 8, 2004. The credit facility requires that the Company pay a 0.375% per annum commitment fee, payable in quarterly installments based on the Companys borrowing base utilization. Prior to maturity, no payments are
required so long as the maximum borrowing base amount exceeds the amounts outstanding under the credit facility. The credit facility requires the Company to monitor tangible net worth and maintain certain financial statement ratios at certain
levels. Substantially all the Companys assets are pledged to secure the credit facility.

Net income (loss) was used as the numerator in computing both basic and diluted income (loss) per common share for the years ended
December 31, 2002, 2001 and 2000. The following table reconciles the weighted average shares outstanding used for these computations.

Year Ended December 31,

2002

2001

2000

Basic Method

17,908,182

17,351,375

9,903,248

Dilutive Stock Warrants





2,842,858

Dilutive Stock Options.





370,535

Diluted Method

17,908,182

17,351,375

13,116,641

The
Companys Series A convertible preferred stock and its stock options are considered to be potential common stock. Additionally, stock purchase warrants issued in the 1999 Private Placement are also considered potential common stock.
Approximately 798,000 stock options and 1,067,000 shares issuable in connection with the convertible preferred stock have not been included in the computation of diluted income per share in 2000, because to do so would have been antidilutive. No
potential common stock amounts have been included in the

33

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)

December 31, 2002

computation of diluted per share in 2002 and 2001 because to do so would have been antidilutive. The calculation of the dilutive effects of
potentially dilutive securities has been calculated under the treasury stock method.

NOTE HIncome Taxes

Income tax expense (benefit) for the years ending December 31, 2002, 2001 and 2000 consists of:

Current

Deferred

Total

Year Ended December 31, 2002:

U.S. Federal

$



88,648

88,648

State









88,648

88,648

Year Ended December 31, 2001:

U.S. Federal

$



1,487,070

1,487,070

State









1,487,070

1,487,070

Year Ended December 31, 2000:

U.S. Federal

$



(1,655,032

)

(1,655,032

)

State









(1,655,032

)

(1,655,032

)

The
following is a reconciliation of the U.S. statutory income to the Companys income (loss) before income taxes for the years ended December 31, 2002, 2001 and 2000:

2002

2001

2000

U.S. statutory income tax

$

83,590

1,482,011

1,429,460

Increase in deductible temporary differences for which no benefit
recorded







Change in the beginning of the year balance of the valuation allowance allocated to
income tax expense





(3,089,767

)

Nondeductible expenses

5,058

5,059

5,275

$

88,648

1,487,070

(1,655,032

)

34

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)

December 31, 2002

The tax
effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at December 31, 2002 and 2001 are presented below.

2002

2001

Deferred tax assets:

Differences between book and tax basis of:

Operating loss carryforwards

$

14,234,869

12,878,565

Statutory depletion carryforward

7,034,566

6,695,115

AMT Tax credit carryforward

1,399,890

1,399,890

Asset related to hedging activities

387,950



Contingent liabilities

132,348

107,848

Other

258,264

229,798

Total gross deferred tax assets

23,447,887

21,311,216

Less valuation allowance

(17,641,358

)

(17,000,473

)

Net deferred tax assets

5,806,529

4,310,743

Deferred tax liability:

Differences between book and tax basis of:

Property and equipment

(5,356,291

)

(4,103,138

)

Total gross deferred liability

(5,356,291

)

(4,103,138

)

Net deferred tax asset

$

450,238

207,605

The
valuation allowance for deferred tax assets increased $640,885 and increased $184,274 for the years ended December 31, 2002 and 2001, respectively. The increase in both years is primarily the result of changes in deferred tax assets. In assessing
the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the
generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in
making this assessment. Based primarily upon the level of projections for future taxable income and the reversal of future taxable temporary differences over the periods which the deferred tax assets are deductible, management believes it is more
likely than not the Company will realize the benefits of these deductible differences, net of the existing valuation allowance at December 31, 2002. The amount of the deferred tax assets considered realizable, however, could be reduced in the near
term if estimates of future taxable income during the carryforward period are reduced.

35

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)

December 31, 2002

The
following table summarizes the amounts and expiration dates of operating loss and investment tax credit carryforwards:

Operating loss carryforwards

Expires

Amounts

2006

$ 3,780,636

2007

8,860,622

2008

4,285,746

2009

3,247,494

2010

6,450,859

2011

600,706

2012

1,939,496

2018

4,530,029

2019

2,546,445

2020

372,409

2021

1,750

2022

4,054,863

$40,671,055

An
ownership change in accordance with Internal Revenue Code (IRC) (S)382, occurred in August 1995 and again in August 2000. The net operating losses (NOLs) generated prior to August 1995 are subject to an annual IRC (S)382 limitation of $1,682,797.
The IRC (S)382 annual limitation for the ownership change in August 2000 is $3,647,700. The latter IRC (S)382 ownership change limitation is a cumulative limitation and does not eliminate or increase the limitation on the pre-August 1995 NOLs. The
NOLs generated after August 1995 and prior to August 2000, are subject to an annual limitation of $3,647,700 less the annual amount utilized for pre-August 1995 NOLs. It should be noted that the same IRC (S)382 limitations apply to the alternative
minimum tax net operating loss carryforwards depletion carryforwards, and alternative minimum tax credit carryforwards. The minimum tax credit carryforward (MTC) of $1,399,890 as of December 31, 2002, will not begin to be utilized until after the
available NOLs have been utilized or expired and when regular tax exceeds the current year alternative minimum tax. Additionally, the statutory (percentage) depletion carryforward of $20,098,759 is considered a special deduction under FASB Statement
109. In accordance with Statement 109, the tax benefits of special deductions are generally recognized in the year they become deductible on the tax return. The unused annual IRC (S)382 limitations can be carried over to subsequent years.

NOTE IProduction Payment Obligation

A production payment was entered into by the Company to
assist in the financing of the Lafitte field acquisition in September 1999. The original amount of the production payment obligation was $2,940,000, which was recorded as a production payment liability of $2,228,000 after a discount to reflect an
effective rate of interest of 11.25%. At December 31, 2002 the remaining principal amount was $1,281,000 and the recorded liability was $978,000. Under the terms of the production payment the Company must make monthly cash payments which approximate
the Companys forty-nine percent share of 10% of the monthly gross oil and gas revenue of the Lafitte field.

The Companys estimate as of December 31, 2002, based on expected production and prices and expected discount amortization is that
projected payments will decrease the liability as follows: 2003, $521,000 and 2004, $760,000.

36

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)

December 31, 2002

NOTE
JStockholders Equity

On
February 1, 2001, the Company completed a public offering of 3,000,000 shares of its common stock at $5.00 per share resulting in net proceeds of approximately $13.2 million to the Company. The Company used the proceeds from the offering along with
other available funds to reduce outstanding debt under its senior credit facility by approximately $13.7 million.

On October 23, 2000, the Company completed a private placement of 1,000,000 shares of common stock at $5.00 per share. Net proceeds from
the private placement amounted to $4,650,000 and were used primarily to accelerate the development of the Companys Burrwood and West Delta fields. An affiliate of a member of the Companys board of directors received $250,000 in
compensation for its service in placing the shares in the private placement.

On February 18, 2000, the Company completed a private placement of shares of its common stock resulting in net proceeds to the Company of $4,500,000. The Company issued 1,533,000 shares of common stock
in its offering. The $4,500,000 in offering proceeds was used to assist in the acquisition and development of the Burrwood and West Delta fields, and to further develop the Lafitte field purchased in 1999.

Common StockAt December 31, 2002 unissued shares
of Goodrich common stock were reserved in the amount of 4,534,000 shares for the exercise of stock warrants issued in connection with the private placement transaction of September 23, 1999 and 330,013 shares for Series A convertible preferred
stock.

Preferred StockThe Series A
convertible preferred stock has a par value of $1.00 per share with a liquidation preference of $10.00 per share, and is convertible at the option of the holder at any time, unless earlier redeemed, into shares of common stock of the Company at an
initial conversion rate of .417 shares of common stock per share of Series A preferred. The Series A preferred stock also will automatically convert to common stock if the closing price for the Series A preferred stock exceeds $15.00 per share for
ten consecutive trading days. The Series A preferred stock is redeemable in whole or in part, at $12.00 per share, plus accrued and unpaid dividends. Dividends on the Series A preferred stock accrue at an annual rate of 8% and are cumulative.

The Company issued 750,000 shares of Series B
convertible preferred stock in connection with its acquisition of the La/Cal II properties on January 31, 1997. The Series B convertible preferred stock had a par value of $1.00 per share with a liquidation preference of $10.00 per share and ranked
junior to the Series A preferred stock. The shares of Series B preferred stock were convertible at the option of the holder at any time, unless earlier redeemed, into shares of common stock of the Company at the conversion rate of 1.12 shares of
common stock per share of Series B preferred stock. The Series B preferred stock was redeemable by the Company prior to January 31, 2001 at $10.00 per share. Dividends on the Series B preferred stock accrued at an annual rate of 8.25% and were
cumulative.

The Company reached an agreement
with all of the holders of its Series B preferred stock in 2001 to exchange each share of Series B for 1.8 shares of its common stock. Concurrent with the closing of its public offering (See Note E), the Company exchanged all 660,839 shares of its
Series B preferred stock into 1,189,510 shares of common stock.

Stock Option and Incentive ProgramsGoodrich currently has two plans, which provide for stock option and other incentive awards for the Companys key employees, consultants and directors. The Goodrich Petroleum
Corporation 1995 Stock Option Plan allows the Board of Directors to grant stock options, restricted

37

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)

December 31, 2002

stock awards, stock appreciation rights, long-term incentive awards and phantom stock awards, or any combination thereof, to key employees
and consultants. The Goodrich Petroleum Corporation 1997 Director Compensation Plan provides for the grant of stock and options to each director who is not and has never been an employee of the Company. Additionally, the Company assumed certain
outstanding stock options of Patrick as a result of the business combination in 1995.

The Goodrich plans authorize grants of options to purchase up to a combined total of 1,587,168 shares of authorized but unissued common stock. Stock options are generally granted with an exercise price
equal to the stocks fair market value at the date of grant, and all stock options granted under the 1995 Stock Option Plan generally have ten year terms and three year pro rata vesting.

In February 2003, the Company cancelled 1,016,500 outstanding
options by issuing 125,157 shares of its common stock to the holders of such options. At the same time, the Company issued 150,000 restricted shares of its common stock, with a three year vesting period, to its employees under the Companys
existing incentive stock option and restricted stock awards plan. As a result of these transactions, the Companys total shares and options outstanding will be reduced by 741,343 shares. Additionally, the Company will be required to record a
charge of approximately $403,000 in the first quarter of 2003 related to the issuance of shares in lieu of rescinded options and to record periodic charges of approximately $40,000 per quarter beginning in the first quarter of 2003 and continuing
through the first quarter of 2006 related to the vesting of the restricted stock.

The per share weighted average fair value of stock options granted during 2002, 2001 and 2000 was $2.43, $2.63 and $3.16 on the date of grant using the Black Scholes option-pricing model with the
following weighted-average assumptions:

2002expected dividend yield 0%, risk-free interest rate of 6%, and an expected life of 5 years; 2001expected dividend yield 0%, risk-free interest rate of 6.0%, and an expected life of 6 years;

38

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)

December 31, 2002

Stock
option transactions during 2002, 2001 and 2000 were as follows:

Number of Options

Weighted Average Exercise Price

Range of Exercise Price

Weighted Average Remaining Contractual Life

Total

Total

Total

Outstanding January 1, 2000

472,884

$0.75 to $24.00

8.5 yrs.

Granted1995 Stock Option Plan

600,000

$

4.99

Granted1997 Director Compensation Plan

12,000

4.88

Exercised1995 Stock Option Plan

(245,696

)

.78

Exercised1997 Director Stock Option Plan

(12,500

)

.79

Expiration of Options

(63,750

)

4.35

Outstanding December 31, 2000

762,938

$0.75 to $24.00

8.9 yrs.

Granted1995 Stock Option Plan

710,000

5.79

Granted1997 Director Compensation Plan

24,000

5.85

Exercised1995 Stock Option Plan

(7,500

)

1.54

Expiration of Options

(24,376

)

7.67

Outstanding December 31, 2001

1,465,062

$0.75 to $18.00

8.7 yrs.

Granted1995 Stock Option Plan

63,000

3.72

Granted1997 Director Compensation Plan

24,000

4.11

Exercised1995 Stock Option Plan

(10,677

)

2.63

Expiration of options

(5,333

)

2.63

Outstanding Dec. 31, 2002

1,536,062

$0.75 to $18.00

7.8 yrs

Exercisable December 31, 2000

129,356

7.59

Exercisable December 31, 2001

349,063

5.21

Exercisable December 31, 2002

764,917

5.32

NOTE KHedging
Activities

The Company enters into futures
contracts or other hedging agreements from time to time to manage the commodity price risk for a portion of its production. The Company considers these to be hedging activities and, as such, monthly settlements on these contracts are reflected in
its oil and natural gas sales. The Companys strategy, which is administered by the hedging committee of the Board of Directors and reviewed periodically by the entire Board of Directors, has been to hedge between 30% and 70% of its production.
A portion of the Companys hedging arrangements are in the form of costless collars, whereby a floor and a ceiling are fixed. It is the Companys belief that the benefits of the downside protection afforded by these costless collars
outweigh the costs incurred by losing potential upside when commodity prices increase. The remainder of the hedges utilized by the Company are in the form of fixed price swaps, where the Company receives a fixed price and pays a floating price. On
January 1, 2001, the Company adopted a formal policy with respect to hedging arrangements in accordance with accounting pronouncements. The Company does not expect its hedging policy or future hedging practice to differ materially from its
historical practice. The Company has no plans to engage in speculative activity not supported by production.

The Companys futures contract agreements provide for separate contracts tied to the New York Mercantile Exchange (NYMEX)
light sweet crude oil and natural gas futures contracts. The contracts contain either specific prices or price ranges known as collars that are settled monthly based on the differences between the contract price or price ranges and the
average NYMEX prices for each month applied to the related contract

39

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)

December 31, 2002

volumes. To the extent the average NYMEX price exceeds the contract price, the Company pays the difference, and to the extent the contract
price exceeds the average NYMEX price, the Company receives the difference.

As of December 31, 2002, the Companys open forward position on its outstanding natural gas and crude oil hedging contracts, all of which were with BNP Paribas, were as follows:

Natural Gas

3000 MMBtu per day swap at $3.50 for January 2003 through February
2003; and

3000 MMBtu per day with a no cost collar of $3.50 and $5.19 per Mmbtu for January through December 2003; and

3000 MMBtu per day swap at $4.06 for January 2003 through December 2003.

Crude Oil

300 barrels of oil per day swap at $28.80 for January 2003 through February 2003; and

200 barrels of oil per day swap at $29.07 for January 2003 through February 2003; and

100 barrels of oil per day swap at $28.95 for January 2003 through February 2003; and

300 barrels of oil per day swap at $27.45 for March 2003 through May 2003; and

200 barrels of oil per day swap at $29.08 for March 2003 through May 2003

The fair value of the natural gas and oil hedging contracts in place at December 31, 2002, resulted, in a liability of $1,108,000.

As of December 31, 2002, $679,095 (net of
$365,667 in income taxes) of deferred losses on derivative instruments accumulated in other comprehensive income are expected to be reclassified into earnings during the next twelve months. During 2002, $1,345,763 in net unrealized loss (net of
$724,642 in income taxes) were recorded to accumulated other comprehensive income and $658,218 in net unrealized losses (net of $354,425 in income taxes) was reclassified from accumulated other comprehensive income to oil and gas sales as the cash
flow of the hedged items was recognized. For the year ended December 31, 2002, the Companys earnings were reduced by $63,667 from cash flow hedging ineffectiveness arising from the natural gas hedging contracts.

The Company has the option to terminate its outstanding oil
and natural gas hedging contracts by paying the amount of the liability. The Company does not anticipate terminating any of its open contracts. The Company is exposed to credit losses in the event of nonperformance by the counterparties to its
hedging contracts. The Company anticipates, however, that counterparties will be able to fully satisfy their obligations under the contracts. The Company does not obtain collateral to support financial instruments but monitors the credit standing of
the counterparties.

Price fluctuations and
volatile nature of markets

Despite the
measures taken by the Company to attempt to control price risk, the Company remains subject to price fluctuations for natural gas and oil sold in the spot market. Prices received for natural gas sold on the spot market are volatile due primarily to
seasonality of demand and other factors beyond the Companys control. Domestic prices for oil and gas could have a material adverse effect on the Companys financial position, results of operations and quantities of reserves recoverable on
an economic basis.

40

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)

December 31, 2002

The
Company entered into the following crude oil hedging contracts, all of which were with BNP Paribas, subsequent to December 31, 2002.

300 barrels of oil per day swap at $32.58 for March 2003 through May 2003; and

300 barrels of oil per day swap at $28.47 for June 2003 through December 2003; and

200 barrels of oil per day swap at $29.32 for June 2003 through December 2003; and

200 barrels of oil per day
swap at $29.97 for June 2003 through December 2003

Subsequent to December 31, 2002, the Company also entered into interest rate swaps to hedge against potential increases in interest rates. The Company has entered into three separate interest rate swaps with BNP Paribas over a three
year period. The first interest rate swap, which has an effective date of February 26, 2003 and a maturity date of February 26, 2004 is for $18,000,000 with a LIBOR swap rate of 1.53%. The second interest rate swap, which has an effective date of
February 26, 2004 and a maturity date of November 8, 2004, is for $18,000,000 with a LIBOR swap rate of 2.25%. The third interest rate swap, which has an effective date of November 8, 2004 and a maturity date of February 26, 2006, is for $18,000,000
with a LIBOR swap rate of 3.46%.

NOTE LFair Value of
Financial Instruments

The following
presents the carrying amounts and estimated fair values of the Companys financial instruments at December 31, 2002 and 2001.

2002

2001

Carrying

Amount

Fair Value

Carrying

Amount

Fair Value

Financial liabilities

Long-term debt (including current maturities)

$

18,500,000

18,500,000

24,500,000

24,500,000

Production payment liability

$

978,321

978,321

1,264,729

1,264,729

Oil and gas derivative assets (liabilities)

Oil

$

(185,759

)

(185,759

)





Gas

$

(922,669

)

(922,669

)

13,000

13,000

The
following methods and assumptions were used to estimate the fair value of each class of financial instruments:

Cash and cash equivalents, accounts receivable, restricted cash, accounts payables and accrued
liabilities: The carrying amounts approximate fair value because of the short maturity of those instruments. Therefore, these instruments were not presented in the table above.

Long term debt and other noncurrent
liabilities: The fair value is estimated using the discounted cash flow method based on the Companys borrowing rates or similar types of financing arrangements.

Oil and gas
derivatives: The fair value is calculated based on the discounted cash flow expected to be received or paid on the derivative utilizing future posted market prices of the underlying product.

41

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)

December 31, 2002

NOTE
MConcentrations of Credit Risk and Significant Customers

Due to the nature of the industry the Company sells its oil and natural gas production to a limited number of purchasers and, accordingly, amounts receivable from such purchasers could be significant. Revenues from these
sources as a percent of total revenues for the periods presented were as follows:

Year Ended

December 31,

2002

2001

2000

Reliant Energy

45

%

56

%

48

%

Conoco, Inc

17

%





Shell Trading

17

%





Genesis Crude Oil, L.P.

5

%

22

%

27

%

Gulfmark Energy, Inc.





10

%

Effective January 1, 2003, the Company contracted with Louis Dreyfus Corporation as its major gas purchaser in lieu of Reliant Energy.

NOTE NCommitments and Contingencies

The U.S. Environmental Protection Agency (EPA) has identified the Company as a potentially responsible party (PRP)
for the cost of clean-up of hazardous substances at an oil field waste disposal site in Vermilion Parish, Louisiana. The Company estimates that the remaining cost of long-term clean-up of the site will be approximately $3.5 million, with
the Companys percentage of responsibility estimated to be approximately 3.05%. As of December 31, 2002, the Company had paid $321,000 in costs related to this matter and accrued $122,500 for the remaining liability. These costs have not been
discounted to their present value. The EPA and the PRPs will continue to evaluate the site and revise estimates for the long-term clean-up of the site. There can be no assurance that the cost of clean-up and the Companys percentage
responsibility will not be higher than currently estimated. In addition, under the federal environmental laws, the liability costs for the clean-up of the site is joint and several among all PRPs. Therefore, the ultimate cost of the clean-up to the
Company could be significantly higher than the amount presently estimated or accrued for this liability.

In connection with the acquisition of its Burrwood and West Delta fields, the Company secured a performance bond and established an escrow
account to be used for the payment of obligations associated with the plugging and abandonment of the wells, salvage and removal of platforms and related equipment, and the site restoration of the fields. Required escrowed outlays included an
initial cash payment of $750,000 and monthly cash payments of $70,000 beginning June 1, 2000 and continuing until June 1, 2005. The escrow agreement was amended in the fourth quarter of 2001 to suspend monthly cash payments and cap the escrow
account at its current balance of $2,039,000. In addition, as part of the purchase agreement, the Company agreed to shoot a 3-D seismic survey over the fields which was completed in the fourth quarter of 2001. The cost of the seismic survey was
approximately $2,500,000.

On February 8, 2000,
the Company commenced a suit against the operator and joint owner of the Lafitte field, alleging certain items of misconduct and violations of the agreements associated primarily with the joint acquisition of and unfettered access to a license to
3-D seismic data over the field. The operator has counter-claimed against Goodrich on the grounds that Goodrich was obligated to post a bond to secure the plugging and abandonment obligations in the field. On November 1, 2002 the 125th Judicial District Court of Harris County,

42

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)

December 31, 2002

Texas, ruled in favor of the Company stating (1) The Sale and Assignment between the Company and the operator assigned the same rights to the
3-D seismic data that the operator had pursuant to the operators data use license agreement from Texaco Exploration and Production, Inc. (TEPI); and (2) Also pursuant to the terms of the Sale and Assignment, Goodrich is required to
post 49% of the bond liability to TEPI at such time that TEPI requests it. The Court has not determined whether TEPI has already issued the request that would require the Company to post 49% of the bond liability to TEPI. However, in a statement to
the Court, TEPI stated that whatever may be the obligation between the operator and Goodrich regarding the requirement, if any, for Goodrich to post a bond in favor of the operator covering Goodrichs P&A obligations, TEPI does not claim
that it is entitled to any bond unless and until the operators total shareholder value (as defined in the Purchase and Sale Agreement between the operator and TEPI) falls below $80 million. The damages portion of the suit is ongoing and it is
too early to predict a likely outcome, however, this action is not expected to have a significantly adverse impact on the operations or financial position of the Company.

The Company is party to additional lawsuits arising in the normal course of business. The Company intends to
defend these actions vigorously and believes, based on currently available information, that adverse results or judgments from such actions, if any, will not be material to its financial position or results of operations.

NOTE ONatural Gas and Crude Oil Cost Data

The following reflects the Companys capitalized costs
related to natural gas and oil activities at December 31, 2002, and 2001:

2002

2001

Proved properties

$

101,016,271

102,730,448

Unproved properties

4,954,897

5,289,301

105,971,168

108,019,749

Less accumulated depreciation and depletion

(38,558,059

)

(32,981,657

)

Net property and equipment

$

67,413,109

75,038,092

The
following table reflects certain data with respect to cost incurred in natural gas and oil property acquisitions, exploration and development activities:

Year Ended December 31,

2002

2001

2000

Property acquisition

Proved

$



175,110

1,198,631

(a)

Unproved



2,186,111

820,200

Exploration

1,128,855

4,174,348

2,797,642

Development

7,843,730

28,972,446

13,862,296

$

8,972,585

35,508,015

18,678,769

(a) Burrwood and West
Delta fields acquisition

43

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)

December 31, 2002

NOTE PRelated
Party Transactions

On June 1, 2001 the
Company entered into a consulting agreement with Patrick E. Malloy, III, a member of the Companys Board of Directors, under which Mr. Malloy provides the Company advice on hedging and financial matters. The contract, which expires in May 2003,
pays Mr. Malloy $120,000 per year. The Company paid Mr. Malloy $120,000 in 2002 and $70,000 in 2001.

On March 12, 2002, the Company completed the sale of a thirty percent (30%) working interest in the existing production and shallow
rights, and a fifteen percent (15%) working interest in the deep rights below 10,600 feet, in its Burrwood and West Delta fields for $12 million to Malloy Energy Company, LLC, led by Patrick E. Malloy, III and participated in by Sheldon Appel and
Josiah Austin, all members of the Companys Board of Directors (Mr. Malloy is now Chairman of the Companys Board of Directors). See Note C for further information regarding the sale.

NOTE QSupplemental Oil and Gas Reserve Information (Unaudited)

The supplemental oil and gas reserve
information that follows is presented in accordance with SFAS No. 69, Disclosures about Oil and Gas Producing Activities. The schedules provide users with a common base for preparing estimates of future cash flows and comparing reserves among
companies. Additional background information follows concerning the schedules.

Schedules 1 and 2Estimated Net Proved Oil and Gas Reserves

Substantially all of the Companys reserve information related to crude oil, condensate, and natural gas liquids and natural gas was
compiled based on evaluations performed by Coutret and Associates, Inc. All of the subject reserves are located in the continental United States.

Many assumptions and judgmental decisions are required to estimate reserves. Quantities reported are considered reasonable but are subject
to future revisions, some of which may be substantial, as additional information becomes available. Such additional knowledge may be gained as the result of reservoir performance, new geological and geophysical data, additional drilling,
technological advancements, price changes, and other factors.

Regulations published by the Securities and Exchange Commission define proved reserves as those volumes of crude oil, condensate, and natural gas liquids and natural gas that geological and engineering data demonstrate with
reasonable certainty are recoverable from known reservoirs under existing economic and operating conditions. Proved developed reserves are those volumes expected to be recovered through existing wells with existing equipment and operating methods.
Proved undeveloped reserves are those volumes expected to be recovered as a result of making additional investments by drilling new wells on acreage offsetting productive units or recompleting existing wells.

SFAS No. 69 requires calculation of future net cash flows using a ten percent annual discount factor and year end prices, costs, and statutory tax rates, except for known future changes such as contracted prices and legislated tax
rates.

The calculated value of proved reserves
is not necessarily indicative of either fair market value or present value of future cash flows because prices, costs, and governmental policies do not remain static; appropriate

44

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)

December 31, 2002

discount rates may vary; and extensive judgment is required to estimate the timing of production. Other logical assumptions would likely have
resulted in significantly different amounts.

Schedule 3 also presents a summary of the principal reasons for change in the standard measure of discounted future net cash flows for each of the three years in the period ended December 31, 2002.

Schedule 1Estimated Net Proved Gas Reserves (Mcf)

Year Ended December 31,

2002

2001

2000

Proved:

Balance, beginning of period

33,956,250

29,510,679

20,849,592

Revisions of previous estimates

29,807

6,070

708,580

Purchase of minerals in place



1,527,172

5,955,477

Extensions, discoveries, and other additions

3,848,920

6,735,556

5,546,322

Production

(2,477,790

)

(3,823,227

)

(3,394,921

)

Sale of minerals in place

(6,287,637

)



(154,371

)

Balance, end of period

29,069,550

33,956,250

29,510,679

Proved developed:

Beginning of period

16,692,390

22,251,970

13,945,540

End of period

15,203,255

16,692,390

22,251,970

Schedule
2Estimated Net Proved Oil Reserves (Barrels)

Year Ended December 31,

2002

2001

2000

Proved:

Balance, beginning of period

8,750,420

6,789,358

5,738,997

Revisions of previous estimates

28,476

(5,602

)

74,369

Purchase of minerals in place



30,829

891,334

Extensions, discoveries, and other additions

120,970

2,517,515

665,911

Production

(451,564

)

(581,680

)

(571,766

)

Sale of minerals in place

(1,006,962

)



(9,487

)

Balance, end of period

7,441,340

8,750,420

6,789,358

Proved, developed:

Beginning of period

3,399,610

3,196,330

2,662,907

End of period

2,556,670

3,399,610

3,196,330

45

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)

December 31, 2002

The
following table summarizes the Companys combined oil and gas reserve information on a Mcf equivalent basis. Estimates of oil reserves were converted using a conversion ratio of 1.0/6.0 Mcf.